WORLD ENERGY OUTLOOK - Jean-Marc Jancovici · 11.9 Combined Cycle Gas Turbine Capacity (MW) 11.10 Nuclear Plants Under Construction and Completed: 1995-2000 11.11 OECD Europe Oil

I N T E R N A T I O N A L E N E R G Y A G E N C Y

WORLDENERGYOUTLOOK1 9 9 8 E D I T I O N

Foreword 3

FOREWORD

The World Energy Outlook 1998, based on a new world energy model,considers energy demand and supply for ten world regions over the periodto 2020. Our aim is not to foretell the future - the uncertainties are toogreat for that. Instead, we see this publication as an opportunity toidentify and discuss the main energy issues that could arise over thisperiod. We use a business as usual projection as a basis for this discussion.

For the analysis of energy demand, we have used the concept ofenergy-related services. Four such services are identified: electricity,mobility, fossil fuel use in stationary energy services and powergeneration. For most world regions, energy consumption in these energy-related services has closely followed the pattern of economic activity.Throughout the book, we chart past data and our future projections todemonstrate their consistency in a simple and transparent manner.

Because the Outlook now projects twenty-five years ahead, we havepaid particular attention to the relationship between cumulative oilproduction to date and estimates of oil reserves. Our analysis of thecurrent evidence suggests that world oil production from conventionalsources could peak during the period 2010 to 2020. There will be noshortage of liquid fuels if this happens because reserves of unconventionaloil are large; but some instability and a possible rise in the world oil pricecould accompany this transfer from conventional to unconventional oilfor additional supplies. This is a highly controversial subject amongexperts in the field. Most past forecasts of reserve limitations on oilproduction have proved wrong. We do not see our analysis as a forecastbut, again, as a way of raising the subject for serious debate.

Our work on natural gas suggests no reserve limitations onproduction at world level before 2020, although increasing use ofunconventional gas in North America is likely.

Analysis of the policies needed to meet the commitments enteredinto at the 1997 Kyoto Conference is being undertaken by many agenciesaround the world. In this Outlook, we include illustrative calculations ofthe scale of the task, using either regulatory or market mechanisms. Thisis a limited study that takes no account of the many flexibilitymechanisms that have been proposed.

This work is published under my authority as Executive Director ofthe IEA and does not necessarily reflect the views or policies of the IEAMember countries.

Robert PriddleExecutive Director

Acknowledgements 5

ACKNOWLEDGEMENTS

This Outlook has been prepared by a team led by Ken Wigley, Headof the Economic Analysis Division of the IEA. The members of the teamwere Fatih Birol, Keith Miller, Atsuhito Kurozumi, Maria Argiri andSylvie Lambert D’Apote. The manuscript was prepared by Faye Bouréand Anne Brady.

The team members have drawn on reports and discussions with awide range of experts, especially our IEA colleagues in the followingoffices: Long Term Cooperation and Policy Analysis; Non-MemberCountries; Energy Efficiency, Technology and Research andDevelopment; Oil Markets and Emergency Preparedness; EnergyStatistics and Information Systems. We have been guided and encouragedin our work by the Director of the Long-Term Office, Jean-MarieBourdaire. We are grateful for discussions with the many experts whoattended the three IEA Workshops on Demand Modelling, PowerGeneration Modelling and Oil Reserves in November 1997 and the twoWorkshops on Biomass Energy in February 1997 and March 1998. Ofcourse, all errors and omissions remain our responsibility.

Comments and questions are welcome and should be addressed as follows:On general topics and the regional chapters:

Fatih Birol Telephone (33-1) 4057.6670E-mail [email protected]

On fossil fuel supply:Keith Miller Telephone (33-1) 4057.6671

E-mail [email protected] regional chapters:

Atsuhito Kurozumi Telephone (33-1) 4057.6672E-mail [email protected]

On power generation:Maria Argiri Telephone (33-1) 4057.6675

E-mail [email protected] biomass:

Sylvie Lambert D’Apote Telephone (33-1) 4057.6507E-mail [email protected]

Address: International Energy Agency9, rue de la Fédération75739 Paris cedex 15 - FranceFax: (33-1) 4057.6659

Table of Contents 7

TABLE OF CONTENTS

FOREWORD 3

ACKNOWLEDGEMENTS 5

PART I Summary:Chapter 1 Introduction 23

2 Assumptions 293 Principal Results 374 Climate Change Analyses 535 Conclusions 59

PART II Outlook for Energy Supply:Chapter 6 Power Generation 63

7 Oil 838 Gas 1239 Coal 143

10 Biomass 157

PART III Outlook by World Regions:Chapter 11 OECD Europe 175

12 OECD North America 20313 OECD Pacific 22714 Transition Economies 24915 China 27316 East Asia 29917 South Asia 32318 Latin America 34719 Africa 37120 Middle East 393

PART IV Tables for the Business As Usual Projection:Energy Demand 411CO2 EmissionsElectricity Generation and Generating Capacity

Definitions (regions and units) 464

World Energy Outlook8

Boxes7.1 Oil Supply7.2 Definitions7.3 Alternative Explanation of the Range in Estimated Ultimate

Oil Reserves7.4 Uncertainty of Reserve Estimates8.1 Gas Supply9.1 Coal Supply

12.1 Energy Market Reforms in US13.1 Regulatory Reforms in Japan and their Impacts16.1 Asian Financial Crisis17.1 Energy Pricing and Subsidies in the Indian Energy Sector17.2 “Dieselisation” of the Indian Energy Sector18.1 Restructuring of the Latin American Energy Sector

Tables2.1 Alternative Paths for Economic Growth Average Annual

Growth Rates % in Gross Domestic Product2.2 Effect of Changes in Economic Growth on World Energy

Consumption and Energy-related CO2 Emissions in 20202.3 Population Growth Assumptions2.4 Assumptions for Business-As-Usual World Fossil Fuel Prices3.1 Oil Supply 1996-2020, Conventional Oil Reserves of 2.3

trillion barrels3.2 Natural Gas Production and Net Imports (Mtoe)4.1 Increases in Energy-Related CO2 Emissions (million tonnes

CO2)4.2 OECD Energy-Related CO2 Emissions in 2010 by Sector6.1 World Electricity Generation, Fuel Consumption and

Generating Capacity 1971-20206.2 New and Total Generating Plant Capacities

and Plant Retirements 1995-20206.3 Capital Expenditure on New Generating Plant6.4 Assumptions for Capital Costs and Efficiencies of New

Generating Plants by Region 1995-20206.5 Assumptions for Nuclear Generating Capacity and Electricity

Generation by Region 1995-20206.6 Assumptions for Hydropower Generating Capacity and

Electricity Generation by Region 1995-2020

Page

8383

108

110123143205228301326333349

30

32

333445

4753

5464

69

7174

75

75

Table of Contents 9

6.7 Assumptions for Generating Capacity and Electricity Generationfrom Renewable Energy Forms by Region 1995-2020

7.1 Oil Demand Assumptions for the BAU Projection7.2 BAU Projection - Total Oil Demand (Mtoe)7.3 BAU Projection - Transport Sector Oil Demand (Mtoe)7.4 BAU Projection - Power Generation Sector Oil Demand

(Mtoe)7.5 BAU Projection - Stationary Sectors Oil Demand (Mtoe)7.6 1995 World Oil Demand - Oil Market Report Basis7.7 World Oil Demand (Business As Usual) - Oil Market Report

Basis (Mbd)7.8 Reserve Estimates by Country (billion barrels)7.9 1994 USGS Ultimate Oil Reserve Estimate as of 1/1/19937.10 Pessimists’ View of Ultimate Oil Reserve Estimate as of

1/1/19977.11 Assumed Ultimate Conventional Oil Reserves (billions of

barrels)7.12 Oil Supply 1996-2020 (million barrels per day)7.13 North Sea Oil Fields’ Recoverable Oil Reserves7.14 Conventional and Unconventional Oil Reserve Estimates7.15 Production Cost Estimates7.16 Identified Unconventional Oil Supply - Thousand Barrels per

Day7.17 Oil Stocks (million barrels)7.18 Oil Demand, Supply and Net Imports Conventional Oil

Reserves of 2300 Billion Barrels - BAU Projection (millionbarrels per day)

7.19 Oil Import Dependence (per cent)7.20 Oil Supply USDOE / EIA - Reference Case (million barrels

per day)7.21 Oil Supply IEA WEO 1998 - BAU (million barrels per day)8.1 Total Primary Energy Supply of Gas (Mtoe)8.2 Total Final Gas Consumption (Mtoe)8.3 Stationary Sector Gas Demand (Mtoe)8.4 Power Generation Gas Demand (Mtoe)8.5 Summary Table for the BAU Gas Projection (Mtoe)8.6 Total Primary Energy Supply (tcf )8.7 USGS Ultimate Conventional Gas Reserves (tcf )8.8 Estimates of Gas Reserves in the United States8.9 Estimates of Canadian Gas Reserves (tcf )

76

84858687

888990

949596

100

101105111113114

116117

118119

120124125125126127128130132133


8.10 BAU Gas Supply and Demand Projections (tcf )8.11 Cumulative Gas Production as a Percentage of the USGS’

Estimated Conventional Gas Reserves8.12 USDOE versus IEA Gas Demand Projections - Annual

Growth Rates 1995 - 20208.13 EU versus IEA Gas Demand Projections - Annual Growth

Rates 1995 - 20208.14 OECD Gas Balances in 2020 IEA BAU versus EU CW (Mtoe)9.1 Total Primary Coal Demand (Mtoe)9.2 Total Final Consumption (Mtoe)9.3 Power Generation (Mtoe)9.4 Coal Reserves and Production 9.5 Percentage of World Coal Reserves by Country (1996)9.6 Percentage of World Coal Production by Country (1996)9.7 Total Primary Energy Supply (1995 - 2020), Annual Growth

Rates10.1 Per Capita GDP, Levels and Growth Rates10.2 Total Final Energy Consumption including Biomass Energy (Mtoe)10.3 Charcoal Production (Mtoe)10.4 Total Primary Energy Supply including Biomass Energy

(Mtoe)11.1 Assumptions for OECD Europe11.2 Total Primary Energy Supply (Mtoe)11.3 Total Final Energy Consumption (Mtoe)11.4 Energy Use in Stationary Sectors (Mtoe)11.5 Energy Use for Mobility (Mtoe)11.6 Total Final Electricity Consumption (Mtoe)11.7 Electricity Generation in OECD Europe (TWh)11.8 Electricity Generating Capacity by Fuel (GW)11.9 Combined Cycle Gas Turbine Capacity (MW)11.10 Nuclear Plants Under Construction and Completed: 1995-200011.11 OECD Europe Oil Balance (Mbd)11.12 OECD Europe Gas Reserves at 1/1/1993 - Trillion Cubic Feet

(tcf )11.13 Gas Balance for OECD Europe (Mtoe)11.14 OECD Europe 1996 Steam Coal Imports by Source

(percentage)11.15 Electricity Generation in OECD Europe and European

Union - 1995 (TWh)11.16 Comparison of Power Generation Projections 1995 - 2020

134137

138

139

140144145147148148149155

166168169171

175176177178181183183185186188189189

190192

197

198

Table of Contents 11

11.17 WEO 1998 BAU versus IEO 1998 Reference Case11.18 Average Annual Growth Rate in Total Final Electricity

Demand 1995 - 2020 11.19 Oil Price Assumptions Real $ per Barrel12.1 Retail Gasoline Prices and Taxes 1997 (US cents per litre)12.2 OECD North America Assumptions12.3 Total Primary Energy Supply (Mtoe)12.4 Total Final Energy Consumption (Mtoe)12.5 Energy Consumption in Stationary Sectors (Mtoe)12.6 Fossil Fuel Use for Mobility (Mtoe)12.7 Total Final Electricity Demand (Mtoe)12.8 Electricity Generating Capacity by Fuel (GW)12.9 Planned Capacity Additions in US Electric Utilities, 1996 to

200512.10 Canadian Nuclear Plants Temporarily Shut Down12.11 Average Power Production Expenses for US Nuclear and

Fossil-fuelled Steam Plants (cents per kWh), 199612.12 OECD North America’s Oil Balance (Mbd)12.13 OECD North America’s Gas Balance (Mtoe)12.14 Comparison of Key Assumptions for the USDOE and the

BAU Projections12.15 Comparisons of Growth Rates of Total Primary Energy

Supply for the USDOE and the BAU Projections13.1 Assumptions for the OECD Pacific Region13.2 Total Primary Energy Supply (Mtoe)13.3 Total Final Energy Consumption (Mtoe) 13.4 Energy Use in Stationary Services (Mtoe)13.5 Energy Use for Mobility (Mtoe)13.6 Total Final Electricity Demand (Mtoe)13.7 Electricity Generation Mix,1995 (TWh)13.8 Non Hydro-Renewable Electricity Generation (TWh) and

Capacity (MW)13.9 Electricity Generating Capacity GW13.10 Fuel Consumption in Power Generation (Mtoe)13.11 OECD Pacific Oil Balance (Mbd)13.12 OECD Pacific Gas Balance (Mtoe)13.13 Comparison of Assumptions for the OECD Pacific Region13.14 Comparisons of Projections of Total Primary Energy Supply

by Fuel for the OECD Pacific Region13.15 Comparison of Power Generation Projections

199200

200204205207208209210212214214

216217

218220222

222

230230232233236236238241

241242242243245246

247


14.1 Eastern European Parameters (excluding Russia)14.2 Russian Energy Parameters14.3 GDP Assumptions14.4 Total Primary Energy Supply by Fuel (Mtoe)14.5 Total Primary Energy Supply (Mtoe)14.6 Total Final Energy Consumption 1990-1995 (Mtoe)14.7 Total Final Energy Consumption (Mtoe)14.8 Per Capita Income Comparison (Based on Official Data)14.9 Energy Consumption in Stationary Sectors (Mtoe)14.10 Energy Consumption in Stationary Sectors (Mtoe)14.11 Energy Demand for Mobility (Mtoe)14.12 Energy Demand for Mobility (Mtoe)14.13 Total Final Electricity Consumption (Mtoe)14.14 Electricity Generation in the Transition Economies (TWh)14.15 Nuclear Power Statistics, 199514.16 Transition Economies Energy Balance 1995 (Mtoe)14.17 Transition Economies Oil Balance - Million Barrels per Day14.18 Transition Economies Conventional Oil Reserves (Billion

Barrels)14.19 Transition Economies Gas Balance 1995 - 2020 (Mtoe)14.20 Annual Growth Rates of Total Primary Energy Supply

(1995 - 2020)14.21 Transition Economies Oil Balance (Mbd)15.1 Importance of China in the World (Percentage of World Total)15.2 Estimates of China’s GDP ($Billion 1990 and PPP) and GDP

per Capita ($ per person)15.3 Assumptions for China Region15.4 Total Primary Energy Supply (Mtoe)15.5 Total Final Energy Consumption (Mtoe)15.6 Energy Use in Stationary Sectors by Fuel (Mtoe)15.7 Energy Use for Mobility (Mtoe)15.8 Total Final Electricity Demand (Mtoe)15.9 Ownership of Major Durable Consumer Goods per 100

Households15.10 Electricity Generation in China (TWh)15.11 Committed Nuclear Projects in China16.1 Economic and Population Data for Selected East Asian

Countries16.2 Energy Demand in Selected East Asian Countries, 1995

(Mtoe)

250250250252253254255256257258258259260262263265265266

267268

270274278

280281282283285286286

287290301

301


16.3 Economic Assumptions16.4 Total Primary Energy Supply (Mtoe)16.5 Total Final Energy Consumption (Mtoe)16.6 Energy Use in Stationary Sectors by Fuel (Mtoe)16.7 Energy Use for Mobility (Mtoe)16.8 Total Final Electricity Demand (Mtoe)16.9 Electricity Sales per Capita and per Customer in Indonesia

(kWh)16.10 Per Capita Income and Per Capita Electricity Generation in

East Asian Countries, 199516.11 Electricity Generation in East Asia (TWh)16.12 Nuclear Plants under Construction in the Republic of Korea16.13 Fuel Use in Power Stations and as a Share of TPES16.14 East Asia Oil Balance (Mbd)16.15 Final Biomass Energy Use in East Asia, 199517.1 South Asian Statistics17.2 Comparison of Average Electricity Retail Price and Supply

Costs in India17.3 Assumptions for South Asia17.4 Total Primary Energy Supply (Mtoe)17.5 Total Final Energy Consumption (Mtoe)17.6 Energy Use in Stationary Sectors by Fuel (Mtoe)17.7 Energy Use for Mobility (Mtoe)17.8 Evolution of India’s Diesel Consumption and Imports (1990-

1996)17.9 Total Final Electricity Demand (Mtoe)17.10 Electricity Generation in South Asia, 1995 (TWh)17.11 South Asia Electricity Generation (TWh)17.12 Indian Nuclear Plant Performance17.13 India’s Estimated Renewable Energy Potential (GW)17.14 Indian Coal Reserves by Type and State, as of January 1995

(billion tonnes)17.15 South Asia Oil Balance (Mbd)17.16 Final Biomass Energy Use in South Asia, 199518.1 Economic and Population Data for Selected Latin American

Countries 18.2 Energy Consumption in Selected Latin American Countries,

1995 (Mtoe)18.3 Energy Price Assumptions for Latin America18.4 Total Primary Energy Supply (Mtoe)

304305306307308309310

311

312313314316318324327

328329329331332334

335336337338339340

341343348

348

351352


18.5 Total Final Energy Consumption (Mtoe)18.6 Energy Use in Stationary Sectors by Fuel (Mtoe)18.7 Energy Use for Mobility (Mtoe)18.8 Total Final Electricity Demand (Mtoe)18.9 Electricity Generation Mix (TWh)18.10 Operating Nuclear Power Plants in Latin America18.11 Hard Coal Production - Colombia and Venezuela (Mt)18.12 Final Biomass Energy Use in Latin America, 199519.1 Economic Performance and Population of Selected African

Countries19.2 Energy Consumption in Selected Africa Countries (Mtoe)19.3 Assumptions for the African Region19.4 Total Primary Energy Supply (Mtoe)19.5 Total Final Energy Consumption (Mtoe)19.6 Energy Use in Stationary Sectors by Fuel (Mtoe)19.7 Energy Use for Mobility (Mtoe)19.8 Total Final Electricity Demand (Mtoe)19.9 African Capacity (GW) and Electricity Generation (TWh)19.10 Hard Coal Production - South Africa (Mt)19.11 Final Biomass Energy Use in Africa, 199520.1 Middle East Assumptions20.2 Total Primary Energy Supply (Mtoe)20.3 Total Final Energy Consumption (Mtoe)20.4 Energy Use in Stationary Sectors (Mtoe)20.5 Energy Demand for Mobility (Mtoe)20.6 Total Final Electricity Consumption (Mtoe)20.7 Electricity Generation (TWh) and Capacity (GW)20.8 Middle East Oil Balance (Mbd)20.9 Middle East Gas Balance (Mtoe)20.10 TPES by Fuel (Annual Growth Rates 1995-2020)

Figures2.1 World GDP Growth, Data and Alternative Projections

($ Billion at 1990 Prices & PPP)2.2 Business-As-Usual Assumptions, Fossil Fuel Prices3.1 World Primary Energy Supply and CO2 Emissions 1971-20203.2 World Primary Energy Supply by Fuel 1971-20203.3 Ratio of World Primary Energy Supply to GDP 1971-20203.4 World Primary Energy Supply by Fuel Type 1971-2020

352353355356357359365367373

373375376376377378380381386387393396396398398400402404405407

31

3537383839


3.5 Annual Rates of Growth 1995-2020 in Total Primary EnergySupply, CO2 Emissions and Energy Intensity

3.6 World Primary Energy Supply3.7 World Energy-Related Services 1971-20203.8 OECD Energy-Related Services 1971-20203.9 Oil Supply Profiles 1996-20303.10 World Power Generation Inputs by Fuel 1971-20203.11 Shares of Fuel Inputs into Power Generation in 20204.1 Comparison of Power Generation by Fuel between BAU and

Kyoto Analyses in 2010 for the Three OECD Regions6.1 World Electricity Generation by Region6.2 World Electricity Generation by Fuel6.3 World Fuel Consumption for Electricity Generation by

Region6.4 World Fuel Consumption for Electricity Generation by Fuel 6.5 World Electricity Generating Capacity by Region6.6 World Electricity Generating Capacity by Fuel7.1 BAU Projection -World Fuel Shares7.2 World Oil Official (proved) Reserves & Production7.3 Non-OPEC Official (proved) Oil Reserves & Production7.4 OPEC Official (proved) Oil Reserves7.5 Generalised Hubbert Curve7.6 Percentage of Discovered Oil Reserves in Production7.7 Oil Supply Profiles 1996-2030 Ultimate Conventional Oil

Reserves of 2300 Billion Barrels7.8 Oil Supply Profiles 1996-2030 Ultimate Conventional Oil

Reserves of 2000 Billion Barrels7.9 Oil Supply Profiles 1996-2030 Ultimate Conventional Oil

Reserves of 3000 Billion Barrels7.10 World outside North America: Giant Oil Fields Recovery

Factor Distributions 1996-19878.1 OECD Europe’s Gas Balance8.2 World Gas Production9.1 World Coal Supply and Demand (Mtoe)

10.1 Per Capita Biomass versus per Capita GDP in DevelopingCountries

11.1 Total Primary Energy Supply in OECD Europe11.2 Fossil Fuel & Heat in Stationary Sectors11.3 Stationary Energy Uses by Fuel11.4 Heating Degree Days

40

40414245495057

666667

676868889192939697

100

103

104

107

136137154157

177178179179


11.5 Stationary Sectors Energy Demand 1971 - 199511.6 Energy Use in Mobility11.7 Total Final Electricity Consumption (Mtoe)11.8 Fuels used in Power Generation in OECD Europe 1971-202011.9 Gas Balance for OECD Europe11.10 Total Primary Energy Supply/GDP Ratio11.11 Transport Energy Demand/GDP Ratio11.12 Electricity Demand/GDP Ratio11.13 Stationary Sectors Energy Demand/GDP Ratio 11.14 Electricity Generation (1995 = 100)11.15 Fuel Use in Power Stations (1995 = 100)12.1 Energy Intensities of Selected OECD Countries12.2 Total Primary Energy Supply, OECD North America12.3 Stationary Uses by Fuel12.4 Mobility12.5 Incremental Changes in Oil Consumption12.6 Electricity Demand12.7 North American Electricity Output12.8 Comparison of the Generating Costs of New Steam Coal and

CCGT Plants, 200012.9 Hard Coal Production and Exports12.10 Comparison of the Price Assumptions for the USDOE and

the IEA Projections13.1 Total Primary Energy Supply, OECD Pacific13.2 Energy Intensity Developments by Industry 1974=10013.3 Energy Use in Stationary Services by Fuel13.4 Energy Demand for Mobility13.5 Ownership of Passenger Cars in Japan (More than 660 cc)13.6 Total Final Electricity Demand13.7 Fuel Consumption in Power Generation14.1 Transition Economies Energy and GDP 1990-199514.2 Total Primary Energy Supply by Fuel (Mtoe)14.3 Total Primary Energy Supply versus GDP (1990-2020)14.4 Total Final Consumption versus GDP (1990-2020)14.5 Energy Consumption in Stationary Sectors (1990-2020)14.6 Mobility versus GDP 1990 - 202014.7 Total Final Electricity Consumption versus GDP (1990-2020)15.1 Shares in Incremental World Primary Energy Supply Growth

(1995-2020)

180182182187190194195196196198198203208209210211212213215

221223

231233234235235237239251252254256257259261275


15.2 Comparison of Energy Intensities Based on Official andMaddison GDP Figures (1978 = 100)

15.3 Total Primary Energy Supply15.4 Energy Use in Stationary Sectors by Fuel15.5 Energy Use for Mobility15.6 Total Final Electricity Demand15.7 Domestic Supply and Net Oil Imports in China15.8 Total Primary Energy Supply including Biomass, 1995-202016.1 Average GDP Growth and 1995 GDP Per Capita16.2 Total Primary Energy Supply16.3 Energy Use in Stationary Sectors by Fuel16.4 Energy Use for Mobility16.5 Vehicle Ownership versus GDP per Capita16.6 Total Final Electricity Demand16.7 Total Primary Energy Supply including Biomass, 1995 - 202016.8 Energy Intensity with and without Biomass, 1995-202017.1 GDP per Capita by Region17.2 Total Primary Energy Supply17.3 Energy Use in Stationary Sectors by Fuel17.4 Energy Use for Mobility17.5 Total Final Electicity Demand17.6 Total Primary Energy Supply including Biomass, 1995-202017.7 Energy Intensity with and without Biomass, 1995-202018.1 Total Primary Energy Supply18.2 Energy Use in Stationary Sectors by Fuel18.3 Energy Use for Mobility18.4 Total Final Electricity Demand18.5 Total Primary Energy Supply including Biomass, 1995-202018.6 Energy Intensity with and without Biomass, 1995-202019.1 GDP and Energy Consumption per Capita by Region19.2 Total Primary Energy Supply 19.3 Energy Use in Stationary Sectors by Fuel19.4 Passenger Vehicle Ownership19.5 Energy Use for Mobility19.6 Total Final Electricity Demand19.7 Oil Supply and Demand19.8 Average Per Capita Final Energy Use in Africa, 199519.9 Energy Intensity with and without Biomass, 199519.10 Total Primary Energy Supply including Biomass, 1995-202020.1 Total Final Energy Consumption versus GDP (1971-2020)

279

281283284285293297300303307308309310320321324326330332334345345350354355356368369372374377378379379384387388390397


20.2 Energy Use in Stationary Sectors versus GDP (1971-2020)20.3 Energy Demand for Mobility20.4 Total Final Electricity Consumption20.5 Middle East Oil Balance20.6 Middle East Gas Production (tcf )

398399400405406

Executive Summary 19

EXECUTIVE SUMMARY

This Outlook aims to identify and discuss the main issues anduncertainties affecting world energy demand and supply over the periodto 2020. It does so in the framework of a “business as usual” projectionwhich assumes energy policies existing before the Kyoto Conference ofDecember 1997 remain in place and that no new policies are adopted toreduce energy-related greenhouse gases.

The Outlook projects world energy demand to grow by 65% andCO2 emissions by 70% between 1995 and 2020 unless such new policiesare put in place. It assumes a rate of world economic growth of 3.1% p.a.(1990 US dollars and purchasing power parity), close to the actual ratesince 1971. Two-thirds of the increase in energy demand over the period1995-2020 comes from China and other developing countries.

Fossil fuels are expected to meet 95% of additional global energy demandfrom 1995 to 2020. Oil is used increasingly to fuel rapidly growingdemands for road and air transport. Coal remains important in powergeneration because of its low cost, when used near to producing areas, inboth developed and developing countries. Where pipelines exist, or canbe put in place, natural gas is the preferred fuel for many applications,especially for new power stations. Restructuring and facilitating theinternational transit of natural gas will need to be extended to allow thefurther use of gas worldwide. Reserves of both oil and natural gas willneed to be further developed worldwide. This is especially the case inRussia and the Caspian Basin, where major opportunities will arise tosupply European and Asian markets.

The oil-importing countries dependence on supplies from theMiddle East will increase until liquid fuels from unconventional sources(shale oil, tar sands and conversion from coal, biomass or gas) begin toplay an increasingly important role as 2020 approaches. Oil prices couldrise during the course of this shift. With increased reliance on MiddleEast oil and the expected transition to the use of non-conventional liquidfuels, the probability of supply disruptions and price shocks could rise.

The Outlook shows the substantial reductions in CO2 emissions thatwill be necessary to meet the commitments made at the KyotoConference. The commitments adopted there will affect the future


growth and pattern of world energy demand. The challenge now is toidentify policies that will ensure that these commitments are in fact met.

New policies will be required if the use of nuclear power andrenewable energy sources is to help reduce fossil fuel consumption andgreenhouse gas emissions. These policies would encourage thedevelopment of new designs for less costly nuclear power plants and findacceptable long-term solutions for radioactive wastes. Unit costs ofrenewable energy must be reduced and, in some cases, environmentalproblems posed by the renewables must be solved.

Energy intensity (energy use per unit of economic activity) willcontinue to fall, as in the past, through the introduction of newtechnologies, economic and industrial restructuring and the substitutionof commercial for non-commercial fuels. These processes have alreadybeen taken into account in the projection. In the past, energy trends havebeen remarkably stable and so major new policies will be required toreduce energy intensity in order to stop the growth in CO2 emissions.Some of these policies will tap the no-regret potential for reducing CO2

emissions. All of these policies will need to take account of economic,social and political constraints.

Rapidly growing electricity demand and the need for climate-friendly technologies in non-OECD countries will require foreigninvestment as well as financing from domestic sources. This, in turn, mayrequire restructuring, privatisation and regulatory changes in theelectricity industries in these countries. The Kyoto Protocol and itsfurther developments will encourage sustainable development projectsthat seek out the lowest cost means of abating CO2 emissions indeveloping countries.

21

PART I

SUMMARY

Chapter 1 - Introduction 23

CHAPTER 1INTRODUCTION

A great many uncertainties surround future energy projections,especially those that look ahead as far as twenty five years. The mainsources of these uncertainties range widely and include:

Economic output and structure, population growth. Projections ofeconomic growth and population vary considerably, especially fordeveloping countries. In the transition economies of the formerSoviet Union and East and Central Europe, the pace of economicrestructuring and the adoption of market economies are uneven,especially for major industrial sectors, and their future is uncertain.Technical change and capital stock turnover. The nature and pace oftechnical change are inevitably uncertain. Furthermore, once newtypes of energy-using equipment become available, the extent towhich they affect energy use, depends on the rate at which they areactually adopted and deployed.Human attitudes and behaviour. As incomes rise, the demand forelectrical appliances and heavier, more powerful cars may continue,or it may slacken off. In high income countries, some saturation inhome heating may appear in the near future, but that is unlikely tobe the case for air-conditioning. The extent and timing of thesepossible changes are uncertain.Fossil fuel supplies and extraction costs. The magnitudes ofeconomically recoverable reserves of oil and natural gas remain amatter of discussion and debate. The careful assessments of expertsbecome dated as new technologies enable additional resources to bediscovered and economically exploited. Production costs have beencut over the last decade with the application of new technologies andcompetitive pressures. Many believe that technical change willcontinue to develop, yielding increasing reserves and low productioncosts for many decades to come. Others believe that greaterattention should be paid to the likelihood of diminishing reserves.Energy market developments. Electricity and gas markets in manycountries are undergoing restructuring, privatisation and shifting tomore competitive structures. Their regulatory systems are being


changed accordingly. Far-reaching alterations have been made in theUnited States and the United Kingdom, and many other countrieshave made moves in this direction. The details differ from onecountry to another. How far these changes will lead to moreefficient industries and lower gas and electricity prices will take sometime to determine.Energy subsidies. In many developing countries, energy prices are setat levels well below the full cost of supply. This is especially true forelectricity and some petroleum products. In some transitioneconomies, heat and electricity are sold very cheaply. Over time,prices are expected to rise to cover the full cost of supply, or thecorresponding import price, whichever is the lowest. This changewill be necessary to make the supply industries financially viable,permit the privatisation of state-owned utilities and encourageforeign investment in energy supplies. It will also assist in reducingCO2 emissions. But the timing of these changes is unknown andtheir effects on energy consumption are difficult to estimate.Changing environmental objectives and policies. Governments haverapidly extended the environmental policies that affect energy,covering particulates, heavy metals, acid gases and greenhouse gases.Perhaps the greatest uncertainty currently affecting energyprojections is that surrounding the policy choices that governmentswill make to meet the commitments they entered into in Kyoto.Energy projections must take all these uncertainties into account.

To present the results of an energy projection exercise, numericalestimates must be offered for future energy demand and supply. At thesame time, the importance of all the associated uncertainties must beconveyed.

Business As Usual ProjectionThe objective of this book is not to state what the IEA believes will

happen to the energy system in future. The IEA holds no such single view.Rather, the aim is to discuss the most important factors and uncertaintieslikely to affect the energy system over the period to 2020. The frameworkchosen is a “business as usual” (BAU) projection. This can be described asan illustration of how energy demand, supply and prices are likely to developif recent trends and current policies continue. It specifically excludes theeffect of new policies that may be adopted in order to meet thecommitments taken at Kyoto. The BAU projection is presented by worldregion, by fuel type, by energy-related service and, in some cases by


consuming sector. This is necessary in order to discuss the impacts of themain uncertain factors.

In fact, the IEA expects that the future for world energy will be quitedifferent from that described in the BAU projection. This is partlybecause economic growth, energy prices, technology and consumerbehaviour will turn out to be different from those assumed for the BAUprojection. The most striking difference will most likely occur becausegovernments in developed countries will want to change things, i.e. toreduce greenhouse gas emissions, particularly for CO2.

ApproachThe methods employed in preparing the projections are described in

the following chapters and appendices. Energy demand has beenanalysed for each world region. Careful attention has been paid to pastand projected energy consumption to provide four principal energy-related services:

• electrical services (total consumption of electricity by finalconsumers);

• mobility (non-electricity fuels consumed in all forms of transport);• stationary services (mainly fossil fuels used for heating in buildings

and industrial processes);• fuels used in power generation.Energy consumed in the first three of these energy-related services

adds up to total demand by final energy consumers.Transparency is achieved by providing graphs of energy

consumption in each of these energy services as compared to income(gross domestic product) for both past and future periods. The purposeis to demonstrate that the methods used to project energy demand do notresult in unexplained divergencies from past experience. Within theframework of the energy-related services, the impact of changes ineconomic activity and energy prices on energy demand have beenestimated in some detail. For some non-OECD regions, energy pricedata are not readily available, thus limiting the scope of the analysis ofenergy demand.

A power generation model built for each region identifies the majorelectricity generation technologies and fuels available. This model is usedto estimate, on a least-cost basis, the fuels required to generate theprojected demand for electricity. Energy inputs into the othertransformation processes (oil refineries, gas works, solid-fuel preparationplants and heat-only plants) are estimated separately.


Total world demands for the three fossil fuels, oil, gas and coal, areobtained by adding up the demands of final consumers, of powergeneration, of the other transformation sectors and changes in fuel stocks.The implications for fossil fuel supply are then considered.

A detailed model for conventional oil supply has been prepared thattakes account of the likely increase in recoverable reserves of conventionaloil arising from the reduction in uncertainties over time as newinformation becomes available on the extent and nature of the reservesand from the application of new technologies. The limitations imposedby finite recoverable reserves on the production of conventional oil areassessed, together with the implications for the production of non-conventional oil (e.g. shale oils and tar sands) towards 2020. Gas andcoal supplies are projected separately on a regional basis. Therelationships between fossil fuel prices and supply availabilities arediscussed in the text, but not formally modelled. A study of biomass use(wood, animal waste and other wastes) has been carried out fordeveloping countries.

Using this approach, the BAU projection provides energy balancesfor ten world regions and eight fuels, based on assumptions for economicgrowth, future population and world fossil fuel prices. Some calculationsare made to illustrate the possible effects of varying the assumptions oneconomic growth and on the recoverable reserves of conventional oil.

Kyoto AnalysisIn the BAU projection, CO2 emissions grow rapidly within the

OECD and in the world at large. It is not possible to prepare aprojection that meets the Kyoto target because the countries involvedhave not yet announced the policies they intend to use. Instead, twostylised analyses have been undertaken. The first indicates the scale ofregulation that would be required by OECD countries to meet theirKyoto commitments. The second indicates the “carbon value” thatwould need to be built into fossil fuel prices to meet the Kyotocommitments.

These two stylised analyses are very different from the approach usedin the last World Energy Outlook published in 1996

1. In that Outlook,

an “energy savings” case provided an estimate of reductions in energy usethat could be achieved by the application of cost effective technologies foradditional energy savings through implied changes in the way consumers

1. World Energy Outlook 1996 Edition, IEA/OECD Paris, 1996.


make choices in the consumption of energy and other goods. Thepolicies needed to bring these changes about were not specified.

Since that publication, the IEA has conducted three majormodelling seminars on climate change policies2:

• “Economic and energy market impacts of implementingquantified emission and reduction objectives under the FrameworkConvention on Climate Change (FCCC)”;

• “Closing the efficiency gap in energy responses to climate change:potential for cost-effective energy and carbon efficiencyimprovements”;

• “Uncertainty and energy policy choices to meet UNFCCCobjectives”.

One of the main conclusions of the second seminar was the politicaldifficulty of capturing the no-regret potential for reducing energydemand and energy-related CO2 emissions. This difficulty arises becauseexisting barriers to the take-up of the no-regret potential, involvingsubsidies, monopoly practices, etc., are part of the broad social consensusand difficult to change.

The two stylised approaches presented in this Outlook attempt toquantify the scale of the task of achieving the Kyoto commitments byOECD countries. They include, but are not limited to, capturing theno-regret potential for reducing energy-related CO2 emissions.

2. Insights from Modelling for Climate Change Policy, IEA/OECD Paris, forthcoming.

Chapter 2 - Assumptions 29

CHAPTER 2ASSUMPTIONS

This chapter discusses the main assumptions for economic growth,population and energy prices for the period 1995 to 2020. Actual datahave been used, where available, for the early years of the period.

Economic GrowthEconomic growth is arguably the most important driver of energy

demand. Table 2.1 provides average economic growth rates for the tenworld regions used in this Outlook. It compares growth rates for the past25 years with assumptions made for the BAU projection and for low andhigh economic growth variants. The BAU assumption broadly continuesthe past world rate of economic growth. All regions are expected toexperience slower growth in the future, except for the transitioneconomies which are assumed to recover rapidly from the economicturmoil of the 1990s. As the shares of the rapidly growing developingcountries are rising, the world average growth rate remains close to itspast level.

In this Outlook, the gross domestic products of different countrieshave been converted into the common currency of US dollars usingpurchasing power parities (PPP) rather than market exchange rates.Purchasing power parities compare the costs in different currencies of afixed, wide-ranging basket of goods and services that includes items bothtraded and not traded in international markets, whereas marketexchange rates are based on international trade and capital movements.For this reason, the gross domestic products of different countries orregions converted using purchasing power parities can provide a morewidely based measure of standard of living. This is important whenconsidering the principal driving force of energy demand and for thecomparisons of energy intensities (energy consumption divided byGDP) between countries.


Table 2.1: Alternative Paths for Economic GrowthAverage Annual Growth Rates % in Gross Domestic Product

The BAU assumption is based on an OECD study1. That workanalysed the main components of economic growth:

• future growth in the labour force and its skills;• future investment and the rate of growth of capital stock;• and improvements in productivity.There are two main reasons why most regions are expected to grow

more slowly in the future than they have in the past. OECD regions areexpected to have falling birth rates and ageing populations. Indeveloping countries, economic growth tends to decline as countriesachieve higher living standards. The OECD study compared the BAUcase of 3.1 per cent per annum economic growth with a “high case” of4.8 per cent per annum. The high case represents a “New Global Age” inwhich the major developed and developing countries implement acombination of successful policies aimed at encouraging world trade,investment flows and competitive markets.

Figure 2.1 plots world economic growth from 1950 to 1995 and fouralternative projections. The IEA high and low economic growthassumptions are compared with the OECD low case - adopted as the IEABAU assumption - and the OECD high “New Global Age”. The

1. The World in 2020: Towards a New Global Age, OECD Paris, 1997.

Low BAU High

1971-1995 1995-2020

OECD North America 2.7 1.6 2.1 2.3OECD Europe 2.4 1.6 2.0 2.3OECD Pacific 3.5 1.4 1.8 2.1Transition Economies -0.5 2.6 3.3 4.0China 8.5 5.0 5.5 6.6East Asia 6.9 3.7 4.5 5.2South Asia 4.6 3.4 4.2 5.1Latin America 3.4 2.7 3.3 4.1Africa 2.6 2.0 2.5 3.5Middle East 2.7 2.1 2.7 4.0

World 3.2 2.6 3.1 3.8


uncertainty surrounding the future rate of world economic growth isclearly substantial. Figure 2.1 shows that the world economy has continuedto grow since 1950. It does not seem unreasonable to assume acontinuation of this growth rate into the future. Countries will, no doubt,try to do better, and maybe they will succeed. But, current financial turmoilin Asia impels caution over future economic prospects. The IEA high andlow economic cases capture the uncertainty over future world economicgrowth. Table 2.2 indicates the impact of this variation on world primaryenergy consumption and CO2 emissions, calculated around the BAUprojection. The 30% range in world Gross Domestic Product impliesranges of some 24% in primary energy consumption and 27% in energy-related CO2 emissions.

Figure 2.1: World GDP GrowthData and Alternative Projections ($ Billion at 1990 Prices & PPP)

Future economic growth is particularly uncertain for China and theTransition Economies. For China, the issue is how to interpret paststatistics in order to assess the past rate of economic growth. The mainproblem lies in the choice of prices used to convert past data for moneyincomes into real incomes. Until recently, many prices in China weredetermined administratively, not by the market. In this study, we use the

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

100000

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

$ Bi

llion

at 1

990

Pric

es a

nd P

PP

OECD High Growth Scenario

OECD Low Growth Scenario - IEA BAU Assumption

IEA High Variant

IEA Low Variant


official Chinese data on gross domestic product in terms of purchasingpower parity. For the Transition Economies, current estimates of GDP arethought to under-record the level of economic activity. In addition, it isdifficult to anticipate the future pace of economic reforms and their effectson economic growth and energy demand. As these cannot be estimatedfrom past data, we have used our own judgments on these issues.

Table 2.2: Effect of Changes in Economic Growth on World Energy Consumption and Energy-related CO2 Emissions in 2020

The Asian financial crisis is currently throwing a shadow over futureeconomic prospects. The most visible effects are sharp falls in exchange ratesand share prices in the Asian countries affected. The immediate concern isthat the stability of the world economy could be affected by these events.

But the underlying problems, and their solutions, are much longer-term. Past investment projects in the crisis-affected Asian countriescreated employment and output so that the economies grew, but withlittle or no profit. Examples are commercial office blocks and factoriesfor which there were no customers. In many cases, these projects werefinanced on short-term bank loans. When the interest on the loans couldnot be paid, the loans were called in. If the loans could not be repaid,borrowers went into receivership and the banks were in difficulties:investment projects were cancelled and share prices plummeted.

Long-term solutions will be difficult to achieve. They involve:• clearer and stricter regulation of the banking and financial sectors;• greater transparency of financial acounts;• improved quality of accountability and risk management in

institutions at all levels;• cutting of links between government and commercial sectors;• greater competition and control of monopoly practices in both

product and financial markets.As these measures are introduced, confidence will eventually return,

bringing with it greater investment and higher economic growth. In theinterim, economic output will be lower than previously expected.

Low Economic BAU Case High EconomicGrowth Case Growth Case

GDP 87 100 117Total Primary Energy Supply 90 100 114CO2 Emissions 89 100 116


Two themes can be drawn from our analysis of this situation:• We are very uncertain about how long it will take for confidence in

the Asian region to return, how low economic activity might fallduring this period and what the economic growth rates willeventually be. Our conclusions are built into the BAU assumptionfor economic growth.

• The 50-year period since World Ward II saw many serious shocksto world economic activity, yet growth persisted over the period.We feel confident that our BAU assumptions are reasonable,provided that the uncertainties are kept in mind.

The energy projections described in this Outlook assume that theeconomic difficulties experienced in Russia during 1998 will not reducethe long-run economic potential of the Russian economy. These recentdifficulties are therefore viewed as altering the short-term path ofeconomic growth and energy demand, they are unlikely therefore tosignificantly alter the energy projections for 2020.

PopulationTable 2.3: Population Growth Assumptions

The assumptions for future world population, set out in Table 2.3,are based on the latest United Nations medium population projection2,in line with the OECD study, The World in 2020 3. The population

Per cent per annum 1995-2020

OECD North America 0.79OECD Europe 0.01OECD Pacific 0.14Transition Economies 0.01China 0.79East Asia 1.16South Asia 1.54Latin America 1.29Africa 2.41Middle East 2.47

World 1.21

2. World Population Prospects, 1950-2050, United Nations, The 1996 Revision, United Nations,Population Division, New-York, 1997.3. The World in 2020: Towards a New Global Age, OECD Paris, 1997.

assumptions have been used mainly for the projection of biomassconsumption in developing countries.

Energy PricesWorld fossil fuel prices are not calculated explicitly in the Outlook.

Instead, judgements are made on future prices based on the relationshipsbetween prospects for demand and supply and on the likely cost ofmarginal supplies.

Assumptions for the BAU projection are listed in Table 2.4 andplotted in Figure 2.2. Fossil fuel prices are held flat at their average 1991-1995 levels. The world oil price is increased between 2010 and 2015 toreflect the expected transition from conventional to unconventional oil asthe source of marginal supply. The arguments are given in Chapter 7.The prices for natural gas in Europe and LNG in Japan (the priceindicator used for the Asian-Pacific regions) are increased in the sameproportion to reflect the close competition with oil products. The worldprice of coal is also increased to take account of the correspondingincrease in transport costs.

The US natural gas wellhead price is increased over the period 2005to 2015 to reflect a possible tightening of the North American gas marketand increased use of unconventional gas. Chapter 8 discusses the reasonsfor this price increase.

Table 2.4: Assumptions for Business-As-Usual World Fossil Fuel Prices

1995 1996 1997 1998-2010 2015-2020

IEA Crude oil import price 15.0 17.5 16.1 17 25in $ 1990 / bbl

OECD Steam coal import price 40.3 39.3 37.2 42 46in $ 1990 / tonne

US Natural gas wellhead price 1.35 1.92 1.96 1.7* 3.5in $ 1990 / thousand cubic ft

Natural gas import price into 89.9 85.7 97.2 103 150Europe in $ 1990 / toe

Japan LNG import price 125.6 130.1 133.4 141 210in $ 1990 / toe


* 1998-2005


0

50

100

150

200

250

300

350

400

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

$ pe

r to

nne

oil e

quiv

alen

t (19

90 p

rices

)

Oil

Gas in EU

Gas in US

Coal

LNG in Japan

Fossil fuel prices in international markets adjust to balance supplyand demand. Where spot and futures markets exist, as for oil, pricesadjust rapidly and are prone to volatility. In the case of the regionalnatural gas markets (Europe, North America and Asia-Pacific), long-termcontracts are important and prices adjust more slowly. But these pricesdo fluctuate, as in all world commodity markets.

The price assumptions set out in Table 2.4 are meant to identifylikely future movements of prices around which short-term fluctuationstake place. For this reason, the fossil fuel price assumptions do not reflectcurrent deviations from trend values, such as the currently low world oilprices.

Figure 2.2: Business-As-Usual AssumptionsFossil Fuel Prices

Chapter 3 - Principal Results 37

CHAPTER 3PRINCIPAL RESULTS

This chapter presents the principal results of the Outlook. Thehighlights of the business as usual demand projection are presented first.These are discussed in more detail for each world region in Part III. Themajor implications for energy supply are then considered. These aremore fully discussed in Part II. As explained in the Introduction, the aimis to identify and discuss the main uncertainties and issues affecting theenergy outlook.

The Business As Usual ProjectionPast and future paths for total primary energy supply, CO2 emissions

and energy intensity are presented in Figures 3.1, 3.2 and 3.3. Oilcontinues to dominate world energy consumption, with transport useincreasing its share. Gas consumption rises to approach coal consumption

0

2000

4000

6000

8000

10000

12000

14000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Tota

l Prim

ary

Ener

gy S

uppl

y (m

illio

n to

nnes

oil

equi

vale

nt)

10000

15000

20000

25000

30000

35000

40000

CO

2 Emissions (m

illion tonnes CO

2)

Energy Demand

CO2 Emissions

Figure 3.1: World Primary Energy Supply and CO2 Emissions 1971-2020


by the end of the period. Nuclear power stabilises. Hydro power andrenewables increase steadily, but remain at low levels. Energy intensityfalls for the world as a whole, at 1.1% per annum (total energy use rises

0

1000

2000

3000

4000

5000

6000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent

Oil

Solid Fuels

Gas

Nuclear

Hydro

Other Renewables

0.12

0.17

0.22

0.27

0.32

0.37

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent

/ $

Bill

ion

at 1

990

Pric

es a

nd P

PP

Figure 3.2: World Primary Energy Supply by Fuel 1971-2020

Figure 3.3: Ratio of World Primary Energy Supply to GDP 1971-2020


by 2% and economic activity by 3.1% p.a.). This continues the trendobserved since 1982. CO2 emissions rise with primary energy demandslightly faster than in the past. Contributing factors are the stabilisationof nuclear power generation and continued rapid growth in coal use inChina and other Asian countries.

For the OECD regions, “solid fuels” contains not only coal andcoke, but also combustible renewable and waste materials (e.g. biomassand industrial and urban waste). This is not the case for non-OECDregions. Figure 3.4 presents the information on world primary energyconsumption in an alternative manner. In this Figure, solid combustiblerenewable and waste materials have been included for all regions. Theyare combined together with hydro power and other renewables under thesingle term “renewables and waste”. They are shown together with fossilfuels and nuclear fuel in a stacked manner so that they add up to totalworld primary energy supply. Energy from renewables and waste risesfrom 1297 Mtoe in 1995 to 1883 Mtoe in 2020, an annual rate ofgrowth of 1.5%.

Regional average annual growth rates for total primary energysupply, CO2 emissions and energy intensity from 1995 to 2020 are givenin bar chart form in Figure 3.5. China and the developing countries areprojected to have major increases in their energy demands

0

2000

4000

6000

8000

10000

12000

14000

16000

1971

1980

1990

2000

2010

2020

mill

ion

tonn

es o

il eq

uiva

lent

Fossil Fuels

Nuclear

Renewables and Waste

Figure 3.4: World Primary Energy Supply by Fuel Type 1971-2020


Figure 3.5: Annual Rates of Growth 1995-2020in Total Primary Energy Supply, CO2 Emissions and Energy Intensity

-2%

-1%

0%

1%

2%

3%

4%pe

r ce

nt p

er a

nnum

TPES CO2 emissions TPES/GDP

OECD N America

OECD Europe

OECD Pacific

TransitionEconomies

China ROW

World

1995 2020

Increase in Energy Demand, 1995 to 2020

OECD 23%

Transition Economies 10%

Rest of the World 44%

China 23%

OECD 54%OECD 42%



Rest of the World 21% Rest of

the World 30%

China 11% China 16%

Figure 3.6: World Primary Energy Supply

Note : ROW (Rest of the World) includes East Asia, South Asia, Latin America, Africa and theMiddle East.


and CO2 emissions. The large falls in energy intensity in the TransitionEconomies and in China reflect current opportunities in these areas formore efficient energy use, but are especially uncertain.

Figure 3.6 emphasises the important contribution made bydeveloping countries to the growth in energy demand between 1995 and2020. China and the other developing countries account for two-thirdsof this increase. The implications for CO2 emissions are discussed inChapter 4.

Energy-Related ServicesIn order to present the main developments in energy demand, it is

important to identify the principal purposes for which energy is used.Four major energy-related services1 have been identified:

• electrical services (total consumption of electricity by finalconsumers);

• mobility (non-electricity fuels consumed in all forms of transport);• stationary services (mainly fossil fuels used for heating in buildings

and industrial processes);• fuels used in power generation.

0

1000

2000

3000

4000

5000

6000

10 20 30 40 50 60 70

Gross Domestic Product ($ Trillion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent

Power Generation

Stationary Uses

Mobility

Electricity Demand

1971 - 1995

1996 - 2020

1. The Energy Dimension of Climate Change and Energy and Climate Change, IEA/OECD Paris,1997, provides a discussion on this approach. A more detailed description of the energy-relatedservices is provided in the definitions in Part IV.

Figure 3.7: World Energy-Related Services 1971-2020


Historical data and future projections for energy used in these energy-related services are shown for the world in Figure 3.7, and for the OECD inFigure 3.8. These data are plotted against economic activity (Gross DomesticProduct) to demonstrate the important relationships between energy demandand economic growth.

For the world and OECD regions, electricity consumption andenergy use to meet mobility needs closely followed economic output upto 1995. They were largely unaffected by the 1973 and 1979 oil priceshocks with the exception, for mobility, of North America in 1979-1982.This exception can be attributed in part to the introduction of CorporateAutomobile Fuel Efficiency (CAFE) standards2 in the US. Fossil fueldemand for stationary heat purposes, on the other hand, was stronglyinfluenced by the two oil shocks. Successful energy efficiency policies, ashift towards service-oriented activities that require less energy to produceand the relocation of some industrial activities to developing countries,explain the stabilisation of heat-related fossil fuel demand in OECDcountries as a whole. Since the late 1970s, most of the increase in thestationary use of fossil fuels for heat services has taken place outside theOECD. Economic development drives the demand for fossil fuel-basedheat, especially for industrial activities, and also leads to the substitution

0

500

1000

1500

2000

2500

3000

8 10 12 14 16 18 20 22 24 26 28Gross Domestic Product ($ Trillion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent

Power Generation

Stationary Uses

Mobility

Electricity Demand

1971 - 19951996 - 2020

Figure 3.8: OECD Energy-Related Services 1971-2020

2. Green D.L., 1990, CAFE or Price, Energy Journal 11: 37-57.


of commercial fuels for non-marketed traditional fuels. Fossil fuel use forstationary services continues to rise with income in developing countries.

In the projection period to 2020, demands for electricity andmobility services continue their past upward trends. Fossil fuel demandfor stationary services tends to flatten out in the OECD regions, butcontinues upward in China and other developing countries asindustrialisation rapidly increases. Energy demand for power generationfollows electricity demand, but growth slows as new generating plant isintroduced with higher efficiency.

In the past, downward pressure on energy use from a steady streamof technological changes that raise energy efficiency has been offset byupward pressure on energy use from increased incomes and changingtastes to produce the persistently linear trends evident in Figures 3.7 and3.8. Care has been taken to chart past data and projections in order todemonstrate that the results obtained from the energy demand projectionmethods used in this study do not produce unexplained deviations frompast trends. The manner in which these two types of pressure will interactin the future contributes to the uncertainty of future energy projections.

Some energy uses will eventually become saturated as incomesincrease. An example is the heating of residential, public and commercialbuildings. In high-income countries, most buildings are already heatedto normal comfort levels. A 50% increase in GDP in these countries willnot mean that buildings will be heated to higher temperatures, althoughthe number and size of such buildings may well increase. It is difficult todetect such tendencies in the data to date and their timing is highlyuncertain.

For the Transition Economies, energy data and their relationships toGDP are difficult to interpret. Energy data collection was disrupted inthe early 1990s and new forms of data collection have been introduced.Some data definitions have been changed from earlier systems, andinconsistencies remain. IEA staff are working with their counterparts inthese countries to improve the quality of energy data. In addition, thetransition to market systems, the restructuring of economies and themodernisation of industry and commerce mean that past statistics areunlikely to be a reliable guide for future energy developments. For allthese reasons, projections of energy demand and supply in this region arebased largely on judgement rather than analysis of the past, and they areespecially uncertain.


Oil Supply ProspectsProspects for oil production have been analysed by region, paying

particular attention to the distinction between OPEC Middle East3 andall other producers. Account has been taken of estimates of conventionaloil reserves and the production profiles for oil in each region. A detaileddiscussion of this subject is provided in Chapter 7.

Oil reserve estimates are inevitably uncertain, and studies normallyreport them as ranges, rather than as point estimates. For example, theUnited States Geological Survey in 1993 reported a range of 2.1 to 2.8trillion (1012) barrels for worldwide recoverable reserves of conventionaloil. Experts differ on these figures; some take a static view, emphasisinggeological and statistical issues that lead to a low reserve estimate, whileothers take a dynamic view, arguing that new information and thereduction of uncertainty will contribute to increases in identified reservesand that rapidly advancing technology will help discover more reservesand make a wider range of already known deposits economicallyrecoverable. Experience in mature oil regions indicates that productionbuilds to a peak when approximately half of the ultimately recoverablereserves has been produced, and then falls away. The application of newtechnologies, such as horizontal drilling and three-dimensional (3D)seismic analysis, determines the ultimate size of recoverable reserves.Technology can extend the peak and delay or slow the decline inproduction. But eventually production falls, given a fixed oil resource.This has been the experience, for example, in the United States.

This approach has been applied on a regional basis. It indicates thata peaking of conventional oil production could occur between the years2010 and 2020, depending on assumptions for the level of reserves. Oilproduction outside OPEC Middle East would peak before OPEC MiddleEast production, producing a greater reliance on OPEC Middle Eastsupply between the two peaks. A plateau in oil production for OPECMiddle East of 47.9 Mbd has been assumed, rather than a sharp peak.

BAU projections for oil production profiles for the world, OPECMiddle East and all other areas are shown in Figure 3.9. Ultimaterecoverable reserves of conventional oil are assumed to be 2.3 trillionbarrels, the modal value adopted by the United States Geological Surveyin 1993. In this Figure, world demand for liquid fuels has been extendedto 2030 at the average growth rate of 1995-2020 in order to illuminatethe longer-term oil supply picture. Table 3.1 gives details of supplies forconventional and non-conventional oil. The use of non-conventional oil

3. Saudi Arabia, Kuwait, the United Arab Emirates, Iraq and Iran.


expands rapidly after 2015 to meet the increase in demand for liquidfuels. It compensates for the decline in conventional oil production.

The extent of any rise in the world oil price associated with thesedevelopments is in some doubt. To produce large and increasing volumesof oil from non-conventional sources will require many multi-billiondollar projects. Some unevenness in supply availability is possible

Table 3.1: Oil Supply 1996-2020Conventional Oil Reserves of 2.3 trillion barrels

Figure 3.9: Oil Supply Profiles 1996-2030

million barrels per day 1996 2010 2020

Total Demand for Liquid Fuels 72.0 94.8 111.5

Total Natural Gas Liquids, processing Gains and Identified Unconventional Oil 9.3 15.9 20.1

Conventional Crude OilMiddle East OPEC 17.2 40.9 45.2World excluding Middle East OPEC 45.5 38.0 27.0Total Crude Oil 62.7 79.0 72.2

World Liquids Supply excludingUnidentified Unconventional Oil 72.0 94.8 92.3

Balancing Item - Unidentified Unconventional Oil 0.0 0.0 19.1

0

20

40

60

80

100

120

140

160

180

200

1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Mill

ion

Barr

els

per D

ay

World Oil Demand

World Crude Oil Supply

World Crude Oil Supply excluding OPEC Middle East

OPEC Middle East Crude Oil Supply

2300 Billion Barrels

Unconventional Oil and NGLs


because of the long lead times required for these big projects and thedifficulties in matching supply to demand in what promises to be ahighly competitive market. But it is necessary to distinguish fluctuationsin the world oil price from its longer-term average level. Some short-termprice movements could well arise from supply-demand mismatches, asnon-conventional oil sources take over the marginal supplier role. Butopinion on the effect of this changeover on the longer-run oil price ismixed. Some observers expect long-run supply costs from major non-conventional oil production projects to be higher than current long-runsupply costs from non-OPEC sources, lifting the world oil price to a newlong-run level of between $25 and $30 per barrel. Others suggest there willbe no upward pressure on the world oil price. In this Outlook, an upwardramp from $17/bbl to $25/bbl has been assumed from 2010 to 2015 as aresponse to the transition to non-conventional oil, with the oil priceremaining at $25/bbl after 2015. All prices are quoted in 1990 US dollars.

A more optimistic view of oil reserves would assume an ultimatestock of recoverable conventional oil of 3 trillion barrels, compared with thelower assumption of 2.3 trillion barrels. This view postpones the productionpeak of conventional oil and the associated rise in world oil prices to 2020.The effect of the lower oil price on world oil demand is estimated to besmall. A more conservative estimate of oil reserves at 2 trillion barrels wouldshift the production peak and possible oil price rise back to 2010.

The range of 2-3 trillion barrels represents our estimate of theuncertainty of the ultimate reserves of recoverable conventional oil. Thisincludes allowances for expected new discoveries, upward revisions of thereserve estimates for identified fields and the impacts of newtechnologies. We are aware that experts differ - some more optimisticand some less so. It may be that new information in the future will causeus to revise our analysis, perhaps to reduce or to increase the range.

Gas Supply ProspectsReserves of natural gas4 are estimated to be equivalent to 1.9 trillion

barrels of oil, similar in magnitude to the lower end of the range ofreserve estimates for conventional oil. Although world demand fornatural gas is growing faster than that for oil (2.6% per annum comparedwith 1.9%), it does so from a much lower base. World natural gasproduction is not expected to peak until well beyond 2020. A fullerdiscussion is provided in Chapter 8.

4. Masters, C. D. et al, World Petroleum Assessment and Analysis, Proc. 14th World PetroleumCongress, 1994.


Table 3.2 shows BAU projections of indigenous gas production andnet imports by region.

For regions other than OECD Europe and OECD North Americaplus Mexico, gas production is assumed to be determined by domesticdemand until cumulative production reaches 60% of ultimate gasreserves in those regions. (This assumption allows for a possible increasein gas reserves in those regions as a result of new discoveries and of newtechnologies that would allow known reserves, now considered to beuneconomic, to be brought into production.) Beyond 60%, gasproduction is assumed to decline at 5% per annum.

In North America, both the Canadian and United Statesgovernments project rising gas production to 2020 at continuing low gasprices. They do not expect indigenous gas reserve constraints to limitsupply or raise gas prices substantially over this period. This view isdiscussed in Chapter 8. The position taken in this study is thatconsiderable uncertainty exists for North America over the impact offuture technological developments on the extent of recoverableconventional gas reserves and on the costs of both conventional and

Indigenous Production 1995 2010 2020

OECD North America (including Mexico) 592 759 764OECD Europe 199 276 238OECD Pacific 31 77 68Transition Economies 585 809 1116China 17 57 81Rest of World (excluding Mexico) 395 750 1208World 1818 2727 3474

Net Imports1995 2010 2020

OECD North America (including Mexico) -2 -2 -2OECD Europe 104 230 387OECD Pacific 42 42 64Transition Economies -74 -162 -281China 0 0 0Rest of World (excluding Mexico) -76 -114 -174

Table 3.2: Natural Gas Production and Net Imports (Mtoe)


unconventional gas production. It is possible that additional natural gascould be discovered and that the production costs of unconventional gascould remain low. It is also possible that some rise in gas prices wouldresult from higher production costs, especially for large volumes ofunconventional gas. A rise in gas price could stimulate further gasproduction from unconventional sources (coal-bed methane) or fromcoal gasification. We are extremely uncertain on these issues. We haveassumed that gas prices in North America will increase linearly from $1.7(in 1990 prices) per thousand cubic feet in 2005 to $3.5 in 2015 andthen remain flat at that level. As a result, gas demand growth slows to2020. Gas production in North America (including Mexico) is assumedto be sufficient to supply this demand. There is clearly a large potentialfor gas demand to grow in North America if gas prices do not rise.

In OECD Europe, gas production is assumed to grow at 2.2% ayear5, until cumulative production reaches approximately 60% ofultimate reserves, and gas production is assumed to decline at 5% p.a.after the production peak.

OECD Europe and OECD Pacific are projected to experience adownturn in gas production at some date during the second decade of thenext century. The timing is uncertain, mainly because estimates of gasreserves (and gas demand growth) are uncertain. Gas imports intoEurope are likely to continue to flow mainly by pipeline from Russia andNorth Africa. Gas imports into Japan and some Asian countries alreadyarrive as LNG.

The assumption has been made that low-income Asian countrieswill not import large quantities of LNG before 2020 because of its highprice. In the rest of non-OECD Asia, some countries are gas exportersand some importers. On balance, non-OECD Asia is not seen as a largenet importer of gas.

World gas demand and supply are balanced in the projection byallocating world net imports to the principal gas exporting regions. Astable business and trading environment, together with adequateregulatory frameworks, will be needed to encourage the mobilisation ofcapital for developing gas production facilities and infrastructure. Onlyunder these conditions will the future development of gas supplies be ableto meet growing world demand for gas.

5. IEA Natural Gas Security Study, IEA/OECD Paris, 1995.


Coal Supply ProspectsWorld coal production is expected to match demand easily over the

period to 2020. The main growth component in coal demand arises inpower generation. The long lead time for power plant construction willallow the parallel development of coal-supply capacity. Theinternational coal market has proven sufficiently flexible to overcomelocal supply deficiencies6.

Electricity Supply ProspectsPower generation systems have been analysed for each region taking

account of differing generating technologies. Requirements for newgenerating capacity have been calculated in light of the rapidly growingelectricity demands in each region, the expected scrapping of ageing powerplants and the reduction of currently large excesses of generating plantcapacity over peak demand in some regions (OECD Europe andTransition Economies). Least-cost criteria are used for projecting thechoice of new generating plants and the dispatching of power plants tomeet demand from OECD regions. A detailed discussion of these topicsis provided in Chapter 6.

Figure 3.10 : World Power Generation Inputs by Fuel 1971-2020

0

500

1000

1500

2000

2500

3000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent

Solid Fuels

Gas

Nuclear

Oil

HydroOther Renewables

6. International Coal Trade, IEA/OECD Paris, 1997.


Over the period 1995 to 2020, some 3500 GW of new electricitygenerating plant are required in the BAU projection. About half of thetotal is projected for China and the other developing countries and athird for OECD countries. This 3500 GW is estimated to have a capitalcost of $3.28 trillion, i.e. an average capital cost of $937 per kW ofcapacity.

Fuels Used for Power GenerationFigures 3.10 and 3.11 plot the changing pattern of fuel use in power

generation in each region. In our projection, future levels of nuclearpower, hydro power and other renewable energy sources have beenassessed on the basis of plans or targets announced by governments andcurrent policies. Decisions on the use of these fuels are mainly politicalor are highly site-specific in nature. In OECD regions, the projectedinputs of oil, gas and coal are calculated from a least-cost despatchingmodel incorporating the higher thermal efficiencies of new generatingplants. In other regions, the projections of fuel mix are based on countryplans and on judgement.

0%

10%

20%

30%

40%

50%

60%

70%

80%pe

r ce

nt

Solid fuels Oil Gas Nuclear Hydro Other Renewables

OECD North America

OECD Europe

OECDPacific

TransitionEconomies

China Rest of the World

World

Figure 3.11: Shares of Fuel Inputs into Power Generation in 2020


Coal use in power generation continues to be important in NorthAmerica, China and in many developing countries. Gas is expected alsoto be important, especially in the Transition Economies. Where suppliesof natural gas are available or are imported, increasing volumes of gas areprojected for use in combined-cycle generating plants. Oil will continueto be used in power generation at times of peak demand and, because itis easily stored, as a standby fuel for use when gas prices increaseseasonally or where gas supplies are unreliable.

There are many uncertainties for future electricity developments,especially the pace of restructuring and changing the form of regulationof the industry in many countries. Expectations are that thesedevelopments will lead to greater efficiency and to electricity prices beingmore closely related to the full costs of supply. Decentralised sourcessuch as combined heat and power production could also lead to increasesin energy efficiency in this sector. As co-generation is already wellestablished in industry, much will depend on the attraction of districtheating or whether technological and regulatory developments willencourage the widespread use of micro-CHP units for use in individualbuildings.

Projections of Biomass Use in Developing CountriesUnlike previous editions of the World Energy Outlook, this

Outlook includes projections of biomass energy use in developingcountries. According to IEA statistics, biomass’s contribution to theworld’s total final energy consumption in 1995 was 930 Mtoe,comparable to those of electricity (932 Mtoe), coal (816 Mtoe) and gas(1019 Mtoe). In many developing countries, biomass (firewood,agricultural by-products, animal waste, charcoal and other derived fuels)provides a substantial share of energy needs, a third in developingcountries on average, but as much as 80% in countries with very low percapita incomes. Some of this biomass is commercially exploited, butmuch is non-commercial. Hence, data on biomass use are difficult tocollect and available statistics are of poor quality. However, it was feltthat the omission of such an important energy source would distort theanalysis of past trends in total energy use and lead to misleadingindications for the future. Considerable work has been carried out by theIEA to assess the current status of biomass energy in developing countriesand to include it in its modelling framework. An extensive discussion ofthese issues is provided in Chapter 10.


For the purposes of this chapter, biomass energy in non-OECDcountries is excluded, so that projections are comparable with thosepresented in previous editions on the World Energy Outlook and withthe projections done by other organisations. Tables summarising theprojections of world energy demand and supply including biomassenergy can be found in Chapter 10.

Similarly, in the Chapters 15 to 19 in Part III, the projections forregional energy demand and supply are shown with and without biomassenergy. The analysis and projections for biomass can be found at the endof each chapter.

Chapter 4 - Climate Change Analyses 53

CHAPTER 4CLIMATE CHANGE ANALYSES

At the time of writing, most governments that accepted greenhousegas emission commitments at the Kyoto Conference have not yetdetermined the packages of policies they will adopt to meet theircommitments. Some actions that reduce carbon dioxide emissions willtake place without policy changes. Estimates of these reductions arealready included in the BAU projection:

• the share of gas in primary energy supply rises relative to oil andcoal, mainly in the provision of stationary energy services andpower generation;

• some additional new nuclear plants are built; • the use of renewables in power generation increases;• energy use rises more slowly than economic activity.But despite these actions, CO2 emissions continue to rise in the

BAU projection, as shown in Table 4.1.

Table 4.1: Increases in Energy-Related CO2 Emissions (million tonnes CO2)

1990 BAU Projected Reduction below BAUprojection increase projection in 2010 required

2010 1990-2010 to meet Kyoto commitments

OECDEurope 3659 4612 953 1246 27%Pacific 1355 1774 419 461 26%North America 5339 7041 1702 2076 29%Transition Economies 4426 3852 -574Annex I 14779 17279 2500 3239 19%

China 2411 5322 2911ROW 3833 8034 4201

World* 21400 31189 9789

* Includes CO2 emissions from marine bunkers.


The extent of the reduction in CO2 emissions in the TransitionEconomies between 1990 and 2010 is especially uncertain. A fall of1291 million tonnes CO2 occurred between 1990 and 1995 and weproject a rise of 717 million tonnes from 1995 to 2010. In order for theeconomies of these countries to grow, they must first modernise theirindustries and commerce. In doing so, they will become more energyefficient and switch to less carbon intensive fuels.

The increases in CO2 emissions projected for China and the rest ofthe developing world between 1995 and 2010 are large - almost threequarters of the total increase for the world.

It is not possible to prepare a projection that describes the paths ofenergy demand and supply, and CO2 emissions, for each world regionwhere countries meet their Kyoto commitments in 2010 without firstknowing what set of policies will be applied and analysing the effects ofthese policies and their interactions. The essential elements for that workdo not yet exist. But it is possible to obtain some idea of where CO2

emissions might be reduced and the types and magnitudes of actions thatwould be required of energy consumers.

Table 4.2: OECD Energy-Related CO2 Emissions in 2010 by Sector

Table 4.2 shows the distribution of OECD energy-related CO2

emissions in 2010 by sector compared with the reduction of 3783 Mtper annum required in 2010 from the BAU projection to meet theKyoto commitment. The bulk of oil use in final energy consumptionis used in transport and is unlikely to be replaced by gas before 2010.

from: million tonnes CO2

Solid Fuels 722Oil 5327Gas 1625Final Energy Consumption 7673

Solid Fuels 3698Oil 331Gas 1227Electricity Generation 5257Other Energy Transformation 496Total Primary Energy Supply 13427

Reduction required to meet Kyoto commitments 3783


CO2 emissions from coal in final energy consumption are too small toallow the required savings to be achieved by fuel substitution in thatcategory. This suggests that the main sources of the reduction (to theextent that it is realised within the OECD countries) must be energy savingin final energy consumption and the substitution of non-fossil for coal-fired electricity generation and we have arbitrarily allocated half of theneeded reductions to these two sectors. As most new OECD generatingplants in the BAU projection are gas-fired, coal use in power generation canbe lowered only by reducing output from existing coal-fired power plants.

The analysis here, purely to illustrate the opportunities andconstraints, is limited to the hypothesis that each OECD region seeks tomeet its own Kyoto commitment in 2010. Within this constraint twoanalyses have been made. In the first, Kyoto Analysis 1, approximatelyhalf the reduction in CO2 emissions is achieved by imposing a uniformadditional reduction of 1.25% p.a. from 1998 to 2010 in energyintensity across all sectors of final demand in all three OECD regions.The other half of the CO2 emission reductions is achieved bysubstituting non-fossil (nuclear or renewable) fuel for fossil fuel in powergeneration.

In the second analysis, Kyoto Analysis 2, the uniform reduction inenergy intensity imposed in the first analysis is replaced by the additionto the prices of fossil fuels in each of the three OECD regions of auniform carbon value, i.e. a uniform charge, reflecting the carboncontent of each fuel, the imposition of which is sufficient to achieveapproximately half the fall in CO2 emissions necessary to meet the fullKyoto commitments.

The calculation of this value is fraught with difficulties. Partlybecause many other factors are at work and partly because end-user priceshave not changed greatly in real terms over the data period, theestimation of price response coefficients for energy demand is anuncertain business. One uncertainty is the time lag between a pricesignal and the response, taking account of the rate of capital turnover.Further, the effects of large energy price increases on energy demand maybe different from those of small price increases because ofmacroeconomic impacts and government policy changes to counteractthem, as in the case of the oil price shock of 1973/74.

With these reservations in mind, the necessary carbon value hasbeen calculated, using the price response coefficients estimated for theOECD regions. Built up linearly over the period 1998 to 2003, therequired value reaches $250 per tonne of carbon in 2003.


This high value demands some explanation. The first reason is theshort period (12 years) over which reductions in CO2 emissions have tobe achieved. This period requires the speeding up of the normal pace ofturnover of capital stock; it does not provide time for new technologies tobe developed and brought into significant use; and there is littleopportunity for the normal learning process to reduce costs. The secondreason is that the analysis makes no allowance for flexible measures thatwould allow the adoption of lower-cost CO2 reductions in the developingcountries and transition economies.

When such a carbon value is added to fossil fuel prices, thecompetitive position between different fuels changes, especially betweenfuels for electricity generation. In the original projection (BAU),substitution was allowed to take place between different types of fossilfuel-fired generating plants, but no substitution was allowed betweenfossil and non-fossil plants, i.e. the levels of power generation fromnuclear and renewable fuels were determined in advance in eachprojection. This limitation was applied because generating cost was notthought likely to be the main determinant of new capacity constructionfor either nuclear or renewable generating plants over the period to 2020.

With these reservations in mind, there are striking differencesbetween the impact of a common carbon value addition to fossil fuelprices in Kyoto Analysis 2 and the uniform reduction in energy intensityimposed in Kyoto Analysis 1. Because of different consumer reactionsand dynamics, changes in fuel use in Kyoto Analysis 2 vary greatlybetween fuels and between different energy-related services. First,throughout the OECD, electricity use and fuel use for mobility are muchless price-sensitive than fossil fuel use in stationary services. Second,energy demand and CO2 emissions in North America are much moreresponsive to an increase in energy price than elsewhere in the OECD.This result has been reported in other studies.1 The implication is thatpolicies aimed at achieving a uniform reduction in energy intensitiesacross sectors and across regions within the OECD are likely to result ina greater welfare loss to consumers than policies which are flexible andallow emissions trading or other mechanisms to equalise the actual (orimplied) carbon values. As noted above, the possibility of JointImplementation of obligations or emissions transfers between Annex 1Parties, or of emissions trading, has not been allowed for. In part, this isbecause of the high level of regional aggregation employed in the study.In this regard, the large reduction in CO2 emissions recorded for the

1. The Costs of Cutting Carbon Emissions: Results from Global Models, OECD Paris, 1993.


Transition Economies in the BAU projection (see Table 4.1) is veryuncertain.

The substitution of non-fossil for fossil power generation required tomeet the Kyoto commitments in addition to the changes made to finalenergy demand in the two Kyoto Analyses, is illustrated in Figure 4.1.

Figure 4.1: Comparison of Power Generation by Fuel between BAUand Kyoto Analyses in 2010 for the Three OECD Regions

In OECD North America and OECD Pacific, total powergeneration is reduced because of the additional electricity saving imposedon final demand in Kyoto Analysis 1 or because of the carbon valueadded to fossil fuel prices in Kyoto Analysis 2. Electricity demand risesin OECD Europe with a carbon value added to fossil fuel prices becauseof a cross-price effect: electricity demand for space and water heating risesas gas prices rise, and this more than offsets the reduction in electricitydemand as a result of the electricity price rise. Where electricity demandgrows more slowly, less new generating plant is built. As this is mostlygas-fired, generation from gas is lower in the Kyoto Analysis than in theBAU projection. In order to meet Kyoto commitments in each region,

0

1000

2000

3000

4000

5000

6000

TWh

Solid Fuels Oil Gas Non-fossil BAU Additional non-fossil

North America

North America

Europe

Europe

Pacific

BAU Kyoto Analysis 1Uniform Energy Intensity Reduction

Pacific Pacific

Europe

North America

Kyoto Analysis 2Uniform Carbon Value


additional non-fossil generation (nuclear or renewable) has progressivelybeen substituted for coal-fired generating plant which has been scrappedearly. In consequence, electricity generation from coal in the KyotoAnalyses is substantially less than that in the BAU projection in eachregion by 2010.

The Kyoto Analyses do not represent expected future outcomes. Inpractice, the policy response is likely to combine changes in price signals,either implicitly or explicitly, with the removal of barriers to the take-upof “no-regret” potential for energy-related CO2 emission reductions. Thelatter could amount to 20-30% of business as usual consumption. Thereare many possible combinations of energy saving and fuel substitutionthat meet the Kyoto commitments. But all involve large deviations frompast trends. It is clear that they will not happen unless adequate policiesand measures are put in place by governments to make them happen.These policies will involve considerable practical difficulties, not leastbecause of the relatively short time remaining to the period 2008-2012 inwhich the Kyoto commitments are to be met. The next step forgovernments is to identify that combination of policies and measures thatbest fits the circumstances of their respective countries, taking account ofcost and political constraints. No account has been taken, in thisassessment, of greenhouse gases other than CO2.

The role of China and the other developing countries indetermining growth in world CO2 emissions (see Table 4.1) underlinesthe importance of these countries to the ultimate solution of thegreenhouse gas problem and the opportunities which exist, in the contextof such high rates of growth in energy demand, to invest cost-effectivelyin the minimisation of greenhouse gas emissions.

Chapter 5 - Conclusions 59

CHAPTER 5CONCLUSIONS

The future development of energy demand, supply and prices inworld regions is subject to many uncertainties. The business as usualprojection, presented in this Outlook, provides a likely outcome ifpolicies remain unchanged, but it is by no means the only outcome.Variations from the assumptions made for economic growth, reserves offossil fuels, and hence world fossil fuel prices, and policies adopted toachieve environmental goals could all produce marked deviations fromthe projections presented in this volume.

The aim of this Outlook is to discuss the nature of theseuncertainties. Not all types of uncertainty have been covered. Theimpacts of future changes in energy technologies are particularly difficultto capture. Specific electricity-generating technologies are identified, butfurther reductions in the unit costs of renewable energy technologiescould occur before 2020, as experience is gained in their use. Furtherwork on combined heat and power (CHP) plants is needed, particularlyon the use of micro-CHP units in individual buildings.

For the OECD countries, persistent trends have been identified inthe relations between economic activity (GDP) and energy use formobility and electrical services. Changes in these trends are possible, forexample, because of saturation in some areas of energy use or as a resultof new policies to reduce the energy intensities of OECD economies.The past trends already reflect the many energy saving policiesintroduced by OECD countries since the first oil crisis in 1973/4.Stronger policies are likely to be needed in the future in order to meetenvironmental objectives, or, if circumstances demand, to assure stabilityin energy supplies. There is lively debate as to how much such policieswill cost, but they are unlikely to be welcome to energy users, even if thereasons for them are well understood.

The choice of policies by countries to meet their Kyoto greenhousegas emission commitments is perhaps the main policy uncertainty atpresent. It is hoped that the analysis presented here will provide usefulinput into the process of choice.

Chapter 61

PART II

OUTLOOK FOR ENERGY SUPPLY

Chapter 6 - Power Generation 63

CHAPTER 6POWER GENERATION

This chapter presents the BAU projection of electricity generationat world level and discusses the methods and assumptions used.Details of the projections for electricity demand and generation ineach region are provided in the individual chapters in Part III. Tablesgiving BAU projections of electricity consumption, fuels used,electricity generation and generating capacities by region are providedin Part IV.

Electricity GenerationThe BAU projections of electricity generation, fuel consumption

and generating capacity are listed in Table 6.1 by energy source.Projected growth rates for fuel consumption are generally less thanthose for electricity generation, as new plants are more efficient thanexisting and retired plants. Except for “other renewables”, projectedgrowth rates for generating capacity are also less than those forgeneration. This reflects the assumption that current excess generatingcapacity in some regions (such as OECD Europe and the TransitionEconomies) will be absorbed over the projection period. The growthrates of generation and capacity also differ because plant load factorschange over time, e.g. coal plants are used generally in base load andgas plants are used increasingly in medium load. “Other renewables”include wind, geothermal, solar and tidal power. The aggregate resultsdepend on the mix of plant types, with different load factors anddifferent conversion efficiencies (following IEA conventions). Forexample, wind power has a low load factor because of its intermittentnature, and 100 per cent conversion efficiency; geothermal power hashigh load factors but conversion efficiency is on the order of 10 percent.

Table 6.1 shows that most new generating plants use gas, mainlyin gas-fired combined-cycle turbines. These plants have lowconstruction costs, are available in a range of small to medium sizes,have short construction times (2 to 3 years), are straightforward tobuild and operate. They also have high efficiency and low pollutant


emissions. Provided gas is available at a competitive price, they are thegenerating plant of choice in the BAU projection1.

Table 6.1: World Electricity Generation, Fuel Consumptionand Generating Capacity 1971-2020

Solid fuel, mainly coal, retains a strong position in powergeneration. It is the favoured fuel where gas is unavailable orexpensive (as in those developing countries that have coal available,like China and India), or in locations close to low-cost coal production

Annual Growth1971 1995 2010 2020 Rate

1995-2020

Electricity Generation (TWh) 5248 13204 20852 27326 3.0%Solid Fuels 2131 5077 7960 10490 2.9%Oil 1100 1315 1663 1941 1.6%Gas 691 1932 5063 8243 6.0%Nuclear 111 2332 2568 2317 0.0%Hydro 1209 2498 3445 4096 2.0%Other Renewables 5 49 154 239 6.5%

Energy Inputs (Mtoe) 1269 3091 4470 5482 2.3%Solid Fuels 618 1362 2023 2521 2.5%Oil 268 308 367 418 1.2%Gas 246 565 1034 1477 3.9%Nuclear 29 608 670 604 0.0%Hydro 104 215 296 352 2.0%Other Renewables 4 34 80 110 4.9%

Capacity (GW) - 3079 4556 5915 2.6%Solid Fuels - 1032 1362 1760 2.2%Oil - 404 527 604 1.6%Gas - 571 1309 2035 5.2%Nuclear - 347 375 334 -0.2%Hydro - 713 940 1109 1.8%Other Renewables - 13 43 73 7.2%

1 The circumstances in which electricity generation from gas has grown rapidly in the UnitedKingdom are discussed in Energy Policies of IEA Countries: United Kingdom 1998 Review,IEA/OECD Paris (forthcoming).


(parts of North America, Australia and South Africa). As indicated inChapter 4, the main threat to coal use in power generation comesfrom future policies to reduce emissions of CO2.

Oil use in power generation grows to 2020, but less quickly thantotal generation. Because of the relative ease and low cost of oilstorage, it is an ideal generating fuel for remote locations where otherfuels are difficult or costly to obtain, for standby or peaking plants andfor use where seasonal variations in price make other fuels (especiallygas) uncompetitive at certain times.

Nuclear generation remains stable in world terms to 2020 as thecommissioning of new plants broadly matches plant retirements. Newnuclear plants are built, in the BAU projection, in those countries thatcurrently have nuclear power building programmes or have nuclearplants currently under construction.

Growth in the use of hydropower, for both base load and pumpedstorage for peaking purposes, is limited by the availability of suitablesites and environmental considerations, particularly in the OECDregions. Projections are based on announced building plans or theexistence of substantial undeveloped hydro capacity.

Electricity generation from other renewable energy sources is thefastest growing category, but will still represent less than one per centof world electricity generation by 2020.

World electricity generation by region and by type of fuel areshown in Figures 6.1 and 6.2. Generation grows strongly in all regionsand is dominated by the OECD, whose world share, nevertheless, isprojected to fall from 60% in 1995 to 47% in 2020. The generationshare of China rises from 8% to 14%, for the Transition Economies itremains at 12% and for the rest of the world, rises from 19% to 27%over the period.

Solid fuels continue as the most important source of powergeneration in the BAU projection but with generation from gas risingmore strongly. Hydropower and oil-fired generation continue to grow,but nuclear generation begins to decline from 2010.

The patterns of world fuel consumption for power generation byregion and by fuel type in Figures 6.3 and 6.4 are similar to thoseshown for generation in Figures 6.1 and 6.2. They differ for thereasons discussed earlier in the chapter.


Figure 6.1: World Electricity Generation by Region

Figure 6.2: World Electricity Generation by Fuel

OECD

Rest of the World

China

Transition Economies

14000

12000

10000

8000

6000

4000

2000

01970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

TWh

0

2000

4000

6000

8000

10000

12000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

TWh

Solid Fuels

Gas

Hydro

Nuclear

Oil

Other Renewables


Figure 6.3: World Fuel Consumption for Electricity Generation by Region

Figure 6.4: World Fuel Consumption for Electricity Generation by Fuel

0

500

1000

1500

2000

2500

3000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Mto

e

Solid Fuels

Gas

Nuclear

Oil

HydroOther Renewables

0

500

1000

1500

2000

2500

3000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Mto

e

OECD

Rest of the World

China



Figure 6.5: World Electricity Generating Capacity by Region

Figure 6.6: World Electricity Generating Capacity by Fuel

GW

3000

2500

2000

1500

1000

500

01995 2000 2005 2010 2015 2020

OECD

Rest of the World


China

0

500

1000

1500

2000

2500

1995 2000 2005 2010 2015 2020

GW

Solid Fuels

Gas

Nuclear

Oil

Hydro

Other Renewables


Generating CapacityBetween 1995 and 2020, world power generating capacity is

projected to increase from 3079 to 5915 GW. New capacityrequirement over the period is 3503 GW, including some 667 GW ofexisting plant expected to be retired over this period. The change ingenerating capacity from one year to the next is the net result ofadditions of new generating plants and the loss from plant retirements.Different types of generating plants are alloted fixed lives and plantretirements are determined by the history of plant commissioning andthese fixed plant lives, on average 40-50 years.

The BAU projections for world generating capacity by region andby fuel type are shown in Figures 6.5 and 6.6. For the regions, thepattern is similar to those for generation shown in Figure 6.1. Theprojection of capacity by fuel type differs in some respects from thatfor generation in Figure 6.2. Figure 6.6 shows gas-fired capacity risingabove coal by 2020, indicating the lower average load factor for gas-fired plants. The generating capacity for hydropower also appearsrelatively higher than for generation because it too has a low loadfactor.

The regional projections for generating capacity, new capacityand for plant retirements are listed in Table 6.2. Some of the oldestplants are located in the Transition Economies, in OECD Europe andin OECD North America.

Table 6.2: New and Total Generating Plant Capacitiesand Plant Retirements 1995-2020

New generating plant capacity (GW)1995-2010 2010-2020 Total 1995-2020

OECD Europe 263 267 530OECD North America 309 260 569OECD Pacific 98 97 195Transition Economies 236 314 550Latin America 158 167 325Africa 56 61 118Middle East 40 87 127China 286 264 550South Asia 113 105 218East Asia 150 171 321World 1709 1794 3503


About a third of the new capacity is projected to be built in theOECD region and about one half in China and the other developingregions. Projections of the capital expenditure needed for newcapacity (excluding new transmission lines) are given in Table 6.3.Over the projection period, the capital expenditure remains a constantshare of Gross Domestic Product, at around one third of one per cent.

Generating plant capacity (GW)1995 2010 2020


Plant retirements (GW)1995-2010 2010-2020 Total 1995-2020


Table 6.2 (continued)


Table 6.3: Capital Expenditure on New Generating Plant

Projection Method for Power GenerationThe projection method for power generation provides a simple,

quantitative framework within which the many issues that arise in thesector may be analysed and quantified. Many of these issues involvecurrent political or institutional trends in electric utilities, such as thefuture of nuclear power or large hydro schemes or the restructuring ofelectricity industries. In other cases, the absence of adequate, relevantdata makes this quantification impossible (as for some developingcountries). For those countries undergoing the transition from acentrally-planned to a market-oriented system, the pace of thattransition and the ultimate form of the electricity industries that willemerge are very uncertain. In these cases, quantitative analysisprovides little assistance, and judgements, supported by discussion ofthe issues, must be used. Even in these cases, however, a simple,quantitative framework is helpful in providing a basis for such adiscussion.

The purpose of the power generation projection is to takeelectricity demand projections and assumptions for fossil fuel pricesand availability and to calculate:

• the amount of any new generating capacity needed;• the type of any new plant to be built;• the amount of electricity generated by each type of plant;

$ Billion at 1990 prices1995-2010 2010-2020 Total 1995-2020

OECD Europe 194 182 376OECD North America 231 222 453OECD Pacific 157 166 323Transition Economies 207 222 429Latin America 211 150 362Africa 47 48 95Middle East 40 68 108China 323 306 629South Asia 125 98 223East Asia 137 144 282

World 1673 1607 3280


• the fuels consumed to generate the estimated electricitydemand;

• and the system short-run marginal cost of generation as the basisfor the calculation of consumer electricity prices.

The calculation needs to simulate, albeit in a highly simplifiedmanner, the way these outputs are determined in practice.

For market economies this means a lifetime, least-cost calculationfor choice of new generating plants and a short-term, least-costcalculation for dispatching existing generating plants. Most state-owned monopolistic utilities have regulatory regimes that require costminimisation, although examples are sometimes reported of choices ofnew plant decided on more political grounds. Where sufficient dataare available on the existing stock of power plants and on the prices ofgenerating fuels, a number of different ways exist for representingthese two cost-minimising calculations.

Where plant or fuel price data do not exist, or where the choice ofnew plant or plant dispatching decisions are not made on a cost-minimising basis, more judgemental methods must be used, based onanalysis of the data that do exist, on a review of the literature and onconsultations with experts in the regions concerned. As morecountries restructure their electricity industries and their associatedregulatory systems on a market basis, it is likely that cost minimisationwill become increasingly the norm over the period to 2020.

Structure of the Power Generation ModelIn the power generation calculations, the demand for electricity

(grossed up to take account of losses in transmission and own-use inthe power sector) is combined with an assumed load curve to calculatepeak load. The need for new generating capacity is calculated byadding a minimum reserve plant margin to peak load and comparingthat with the capacity of existing plants less plant retirements usingassumed plant lives. An allowance is needed for assumed plantavailability. If new plant is needed, the choice is made on the basis oflevelised cost. This is a technique widely used in the power sector byother modellers and by the IEA and NEA in their publications oncomparative generating costs2. The levelised generating cost(expressed as money value per kWh) combines capital, operating andfuel costs over the whole operating life of a plant using a givendiscount rate and plant utilisation rate.

2 Projected Costs of Generating Electricity, IEA/NEA, OECD Paris, forthcoming.


Care has to be taken for each type of generating plant to ensurethat sufficient supply of the resource or fuel is available to meet thedemand for power generation (in addition to demand from otherusers) calculated for the region in the period in question. Mostrenewable resources are limited in capacity as is the availability ofsuitable sites. In some regions, the supply of natural gas may belimited by the resource available, the rate at which physical deliverysystems and necessary regulatory structures may be put in place or theconstruction of LNG tankers, liquefying and gasifying facilities, etc.These problems are not assumed to apply to coal or oil. Becauseinvestments in nuclear and renewable plants have costs that are highlysite- and country-specific and are frequently determined on a semi-political basis, they are determined by assumption. For reasonsdiscussed earlier in the chapter, some allowance has to be made for oiluse in peaking plant. The projection method ensures that annual oiluse remains below 2500 hours in OECD Europe, 2250 hours inOECD North America and 3500 hours in the OECD Pacific region.

Once the existing set of plants has been determined, fossil fuelprices are used to load plants in ascending order of fuel and operatingcost, allowing for assumed plant availability. Once the generation ofeach type of plant has been determined, the fuel requirements arecalculated using plant efficiencies.

The marginal generating cost of each system is obtained bycalculating the weighted average marginal cost over the load curve,using as weights the generation in each period.

Assumptions and Data SourcesNew Generating Plants

Assumptions for the capital costs and efficiencies of newgenerating plants are listed in Table 6.4 by region. These figures aredrawn from a wide variety of sources, including IEA studies3, reportsfrom the United States Energy Information Administration, nationalsources and the trade and business press. They should be treated withgreat caution. In a few cases they are based on observations made onactual new plants. In many cases, however, they are drawn fromproject proposals that may be subject to upward or downward bias. Inany case, estimates vary widely in the literature, and some judgementhas been exercised in choosing ‘‘typical’’ values. Capital costs arenoticeably higher for new generating plants in Japan than elsewhere.3. Projected Costs of Generating Electricity, IEA/NEA, OECD Paris, forthcoming.


Table 6.4: Assumptions for Capital Costs and Efficienciesof New Generating Plants by Region 1995-2020

* pumped storage

Nuclear and Renewable GenerationAssumptions for future generating capacity and electricity

generation by region for nuclear power are provided in Table 6.5 andfor hydropower in Table 6.6. Detailed discussion of these assumptionsmay be found in Part III.

Table 6.7 provides similar information for four renewablecategories. Again, some further details are given in Part III and in aforthcoming IEA report4. In many cases, the low or zero figures fordeveloping countries represent a lack of adequate data, even for 1995.

4 Renewable Energy Policy in IEA Countries, Volume I (1997) and Volume II (forthcoming 1998),IEA/OECD Paris.

OECD OECD OECDEurope North America Pacific China Rest of World

1995 2020 1995 2020 1995 2020 1995 2020 1995 2020

Steam boiler - coalCapital cost ($/kW) 1025 1025 940 940 2130 2130 750 750 1000 1000Efficiency % 38 40 38 40 40 42 35 38 35 38

CCGT - gasCapital cost ($/kW) 640 380 430 380 850 680 450 450 450 450

Efficiency % 52 60 52 60 47 56 50 55 50 55

GT - gas or oilCapital cost ($/kW) 340 310 270 260 640 510 275 275 275 275

Efficiency % 36 45 36 45 36 42 35 39 35 39

NuclearCapital cost ($/kW) 2000 2000 3000 3000 2000 2000 2000 2000

HydroCapital cost ($/kW) 2500 2500 2500 2500 3500*3500* 2000 2000 2000 2000

Wind (availability 25%)Capital Cost ($/kW) 1000 1000 1000 1000 1000 1000 1000 1000

GeothermalCapital cost ($/kW) 2000 2000


Table 6.5: Assumptions for Nuclear Generating Capacity and ElectricityGeneration by Region 1995-2020

Table 6.6: Assumptions for Hydropower Generating Capacity andElectricity Generation by Region 1995-2020

1995 2010 2020Capacity Electricity Capacity Electricity Capacity Electricity(GW) (TWh) (GW) (TWh) (GW) (TWh)

OECD Europe 126 861 127 863 107 729OECD North America 116 812 96 697 59 437OECD Pacific 41 291 59 418 73 515Transition Economies 41 216 44 257 29 181Africa 2 11 2 12 2 12China 2 13 11 72 20 127East Asia 14 102 28 205 37 267Latin America 3 18 4 30 4 30Middle East 0 0 0 0 0 0South Asia 2 8 3 15 4 19

1995 2010 2020Capacity Electricity Capacity Electricity Capacity Electricity(GW) (TWh) (GW) (TWh) (GW) (TWh)

OECD Europe 167 486 188 585 201 629of which Pumped Storage Hydro 30 - 32 - 34 -OECD North America 165 648 172 680 177 703of which Pumped Storage Hydro 22 - 22 - 22 -OECD Pacific 56 126 69 145 73 152of which Pumped Storage Hydro 23 - 30 - 33 -Transition Economies 88 290 95 340 104 375Africa 20 56 26 72 30 84China 52 191 125 457 199 726East Asia 25 78 40 131 55 185Latin America 109 495 170 803 207 980Middle East 5 16 10 32 10 32South Asia 26 112 46 200 53 229

Note : Hydro output excludes output from pumped storage plants.


Table 6.7: Assumptions for Generating Capacity and Electricity Generationfrom Renewable Energy Forms by Region 1995-2020

1995 2010 2020Capacity Electricity Capacity Electricity Capacity Electricity

(GW) (TWh) (GW) (TWh) (GW) (TWh)OECD EuropeGeothermal 0.7 4.1 1.6 10.2 1.9 12.7Wind 2.3 4.0 15.0 32.9 30.0 65.7Sol/Tide/Other 0.8 1.8 1.2 2.6 1.7 3.8Waste 5.5 30.2 7.8 42.5 9.8 53.5OECD North AmericaGeothermal 3.0 14.9 3.0 19.6 3.0 19.9Wind 1.9 3.3 3.5 7.7 5.5 13.0Sol/Tide/Other 0.4 0.9 0.7 1.8 1.1 3.0Waste 12.5 67.0 14.8 79.6 16.4 88.2OECD PacificGeothermal 0.8 5.3 2.1 14.5 3.3 22.9Wind 0.0 0.0 1.0 3.1 2.9 8.6Sol/Tide/Other 0.0 0.1 0.5 0.7 2.8 3.7Waste 4.0 17.7 4.6 20.6 5.1 22.7Transition EconomiesGeothermal 0.0 0.0 0.0 0.0 0.0 0.0Wind 0.0 0.0 0.0 0.0 0.0 0.0Sol/Tide/Other 0.0 0.0 0.0 0.0 0.0 0.0Waste 0.6 2.8 0.6 2.8 0.6 2.8AfricaGeothermal 0.0 0.4 0.4 2.1 0.5 3.1Wind 0.0 0.0 0.4 0.9 0.7 1.5Sol/Tide/Other 0.0 0.0 0.0 0.0 0.1 0.1Waste 0.1 0.3 0.1 0.6 0.1 0.6ChinaGeothermal 0.0 0.0 0.3 1.6 0.4 2.5Wind 0.2 0.0 2.3 4.9 3.7 8.1Sol/Tide/Other 0.0 0.0 0.1 0.1 0.1 0.2Waste 0.0 0.0 0.1 0.4 0.2 0.7East AsiaGeothermal 1.4 8.0 6.1 33.8 8.8 48.7Wind 0.0 0.0 0.0 0.0 0.0 0.1Sol/Tide/Other 0.0 0.0 0.0 0.0 0.0 0.0Waste 0.1 0.3 0.2 0.6 0.5 1.5Latin AmericaGeothermal 1.0 6.7 1.4 9.1 1.7 11.2Wind 0.0 0.0 0.4 0.2 0.5 0.2Sol/Tide/Other 0.0 0.0 0.0 0.0 0.0 0.0Waste 2.0 9.6 3.0 13.1 3.9 17.1Middle EastGeothermal 0.0 0.0 0.0 0.0 0.0 0.0Wind 0.0 0.0 0.0 0.0 0.1 0.0Sol/Tide/Other 0.0 0.0 0.0 0.0 0.0 0.0Waste 0.0 0.0 0.0 0.0 0.0 0.0South AsiaGeothermal 0.0 0.0 0.0 0.0 0.0 0.0Wind 0.0 0.1 3.3 7.3 4.0 8.8Sol/Tide/Other 0.0 0.0 0.3 0.5 0.5 1.1Waste 0.1 0.0 1.0 4.6 1.7 7.3

Note: The sum of geothermal, wind, solar, tide and other is classified as “other renewables” inthe regional chapters. Waste is included with solid fuel output.


Data on Existing Generating PlantsData on capacities of generating plants by region and by fuel type

as well as other characteristics of generating plants, such as operatingefficiencies, plant lives, are drawn from a wide variety of sources,including estimations from IEA data, the Utility Data Institute5,country statistical reports, consultants’ reports and the business andtrade press.

Limitations of the Power Generation Projection MethodRegional Variations in Fuel Prices

The power generation model considers each region as a singleutility with a single price for each generation fuel. This is seldom thecase for a single country, and is certainly not the case for any of theworld regions considered in this Outlook. For example, in OECDEurope, coal prices are much higher in Germany and gas prices aregenerally lower in the Netherlands and in Italy than in other Europeancountries. Adjustments for such regional differences in fuel prices aremade in the projection both in the merit order calculation and in thechoice of new plant, as well as in calculating the average prices forgenerating fuels for the region.

Uncertainties in Plant ParametersThe future values of capital and operating costs of different types

of generating plants and their efficiencies are not known with precisionand may vary from one country to another within a region. For thisreason, formal cost-minimising calculations must be treated withcaution. The actual outcome of dispatching and new-plant choice islikely to include some near-optimal options in addition to the optimalchoices. In the projections, new plant technologies with levelised costsnear the minimum value are included in the new-plant mix.

Uncertainties Faced by UtilitiesWhen facing an uncertain future for prices of generating fuels and

growth rate in electricity demand, utilities are likely to choose aportfolio of generating plant types rather than a single, optimal choice.This is another reason why some near-optimal choices for newgenerating plant types are included with the optimal choice calculatedin the projection.

5 World Power Plant Database, Utility Data Institute, McGraw-Hill Co., Washington, DC, USA, 1996.


Local ConstraintsFor some countries within a region, capacity constraints on

natural gas pipelines may limit the rate at which electricity generationfrom gas may grow. These are likely to be resolved over time in adeveloped region such as OECD Europe. More care needs to be takenon this issue for less developed regions such as Asia where there isgreater reliance on seaborne LNG trade. In some cases, the existenceof electricity transmission constraints may need to be taken intoaccount. But no account has been taken of these constraints in thisOutlook.

Environmental ConstraintsEnvironmental regulations, including those for emissions of

sulphur, NOx and particulates, are already in place in many countriesand their impacts on plant dispatching and choice of new generatingplants are likely to grow. These emission considerations are notexplicitly included in the BAU projection. For new plants, these can,to some extent, be accommodated by limiting the range of new-planttechnologies considered. The BAU projections do not include policiesintroduced to meet commitments made at the COP-3 Conferenceheld in Kyoto.

Limits to Fuel SubstitutionChanges in the prices for generating fuels can produce changes in

the merit-order of plant and the dispatching programme. In practice,the opportunities for a coal plant in one country, for example, tosubstitute for a gas plant in another will depend on the capacity ofinternational grid connectors and the arrangements for electricitytrade. In general, these are limited, although electricity trade betweenworld regions may grow in importance in the future. In the BAUprojection, limits are included for the extent of fuel substitutionarising from changes in relative prices to take account of internationaltrading constraints.

Electricity Industry RestructuringThe restructuring of electricity industries from vertically-

integrated utilities, each with its own service area, into morecompetitive structures with new types of regulation, has taken place ina number of countries: in the United Kingdom, the Nordic countries,


New Zealand, Australia, Chile, Argentina and elsewhere. The tradingof electric power between regions has been widespread in the UnitedStates and many individual states are moving to more market-orientedsystems. The 1996 electricity directive6 in the European Union (EU)calls for increased competition in EU countries by 1999 (for Belgiumand Ireland by 2000 and for Greece by 2001). Two alternative systemsare allowed, the Third Party Access (TPA) system and the Single Buyer(SB) system. The degree of competition expected to result under thisdirective will depend on how the measures are implemented byindividual countries. In some cases, for example in the UnitedKingdom, electricity-market restructuring has already been taken wellbeyond the requirements of the directive.

In many developing countries and countries in transition,restructuring is also taking place in electricity industries. Theemphasis here is on privatisation and commercialisation, rather thanon the creation of a competitive electricity industry. The moreimmediate aim is to improve the financial viability of the industry.

Some issues arising from increased competition in electricityindustries are listed below.

Lower Generating Costs and Electricity PricesIncreased direct competition between generators is likely to lead to

reductions in unit costs at power stations and headquarters ofgenerating companies. Cuts in labour force of up to 50% were madein United Kingdom generating companies in the five-year periodfollowing restructuring in 1990, with increased power output. Whereplant availability allows, greater competition is likely to see theincreased use of low-cost generating plant as the competitive generatingsystem seeks to minimise cost. Preliminary analysis by the USDepartment of Energy7 suggests that increased use of existing low-costcoal-fired generating plants (by about 5%) may substitute for gas andoil-fired plant in the United States. The combined effect of these twofactors will lower the costs of generation. Two other matters will affectelectricity prices. The first is that commercial enterprises will seek ahigher rate of profit on capital because of the more uncertain businessenvironment in a competitive market, as well as the need to provide asufficient dividend to shareholders and provide for growth in the

6. Concerning Common Rules for the Internal Market in Electricity, EU Directive, 1996.7. Modeling Electricity Restructuring using POEMS: Shaping Competitive Prices through CostSharing and Shifting, John Conti et al., USDOE 1997.


business to maintain share price. In addition, reductions in overheadcosts at headquarters, R&D expenditures, etc., can be expected to takeplace. The net effect of these trends is likely to be reductions in realelectricity prices as electricity markets become more competitive. Inthe BAU projection, the mark-up from average generating systemmarginal cost to electricity price is reduced over the projection period.

Implications for RenewablesThe emphasis on cost minimisation in a competitive market

implies a stricter cost criteria for renewable technologies than in amonopoly structure. Under either structure, governments may, if theywish, provide financial support for some forms of renewable energy.This support can also be market-tested by inviting competitive tendersfrom renewable energy suppliers to provide specified elements of newcapacity. In some cases, and in the longer term, greater marketflexibility may provide scope for some renewable applications byelectricity consumers. The contribution from renewables in thebusiness as usual projection is based on assumptions.

Implications for Co-generationGreater flexibility for autoproducers to sell their production in

the electricity market may encourage cogeneration by industrial andlarge service-sector establishments. This would reduce electricitydemand on other generators, reduce “heat” supplies from othersources and lead to increases in efficiency and lower emissions. In theBAU projection, a rising path of heat demand is assumed andcorresponding reductions in fossil fuel consumption are made withina total projection of energy demand for stationary energy services (seeChapter 3). Electricity produced in association with this heat isincluded in the power generation projection.

Role of Merchant Generating PlantsA competitive electricity market provides increased opportunities

for generators to invest in generating capacity, not just to meetcapacity and reserve requirements, but to displace existing higher-costplants. To be successful, these new plants must have a lower levelisedcost (that takes account of all capital, operating and fuel costs) thanthe short-run marginal cost of the plant to be displaced. The resultcould be lower electricity prices.


Changes in the Shape of the Load CurveThe emergence of more differentiated electricity products - for

example, wider and more flexible interruptible contracts - may lead toa flatter peak and higher shoulder sections in the load curve.

ConclusionsThe projection method used for the power sector in this Outlook

employs an explicit description of different electricity-generatingtechnologies. It separates electricity demand, generation, generatingcapacity, new generating-plant construction, plant retirements,efficiencies and fuel consumption. It adopts cost minimisation in thechoice of new generating plants and in the use of existing plants. Itsstructure, the numerical values of its parameters and assumptions, andits results are, however, subject to many uncertainties. A great manyjudgements, as well as considerable computation, have been made inthe power projections presented here. In this sense, the projectionsfollow the main thrust of this Outlook - to provide a quantitativeframework for discussing the main factors and uncertainties affectingthe future of energy supply and demand.

CHAPTER 7OIL

Box 7.1: Oil Supply

Oil has the largest share of any fuel in world primary energysupply. Transport fuels are the fastest growing element andcurrently account for over half of oil demand. The remainder isused mainly for heating in buildings, industrial processes, powergeneration and for non-energy uses. Oil products can be easilytransported and stored. Other fuels, such as coal, gas, nuclearpower, hydro and other renewables are less flexible, but once theassociated equipment, delivery infrastructure and contracts havebeen put in place, they tend to be used in preference to oil becausethey have a lower marginal cost in the short-term. In manycountries, oil serves, in this sense, as a residual fuel.

This chapter presents projections of oil demand and supply.Definitions of the sources of oil supply, including production ofconventional and unconventional oil, are provided in Box 7.2 togetherwith definitions of oil reserves. Following a brief review of thebusiness as usual projection of world oil demand, the chapter discussesthe uncertainties surrounding future oil production and the extent ofrecoverable oil reserves, and analyses the relationship between them.

Box 7.2: Definitions

Oil is defined to include all liquid fuels and is accounted at theproduct level. Sources include natural gas liquids and condensates,refinery processing gains and the production of conventional andunconventional oil1. In the Outlook, stock changes are included inoil demand. Oil is considered unconventional if it is not producedfrom underground hydrocarbon reservoirs by means of productionwells and/or it needs additional processing to produce syntheticcrude. More specifically, unconventional oil production is based on

Chapter 7 - Oil 83

1. The definition of unconventional oil is a shortened version of that given in Oil Information,IEA/OECD Paris, 1997.


the IEA’s Oil Market Report (OMR) definitions and includes thefollowing sources, listed in order from the heaviest to the lightestoriginal resource:

• Oil Shales;• Oil Sands-based Synthetic Crudes and Derivative Products;• Coal-based Liquid Supplies;• Biomass-based Liquid Supplies;• Gas-based Liquid Supplies.In 1996, production of unconventional oil, using this

definition, amounted to 1.2 million barrels per day (Mbd).Production of natural gas liquids (including condensates) andrefinery processing gains amounted to 6.7 Mbd and 1.5 Mbdrespectively. Total oil supply in 1996 was 72 Mbd. Table 7.16provides a breakdown of unconventional oil supplies and includesextra heavy oils such as Orinoco, as the latter has an API of lessthan 10°.

In this study, the term resources refers to oil in the ground,regardless of whether it can be recovered or not. The term reserves,or recoverable reserves, refers to that portion of resources that isbelieved to be recoverable with current or prospective technologyand oil prices.

Ultimate reserves is the sum of production to date, identifiedand unidentified reserves. Identified reserves can be split intoproved (high probability of being recovered), probable (mediumprobability) and possible (low probability) categories.

Oil DemandThe oil demand projections outlined in this chapter, and

discussed in more detail in the regional chapters, have been preparedusing a suite of regional energy models. The main assumptions usedin preparing the BAU oil demand projections are shown in Table 7.1below.

Table 7.1: Oil Demand Assumptions for the BAU Projection

1997 1998-2010 2015 2020Oil Price $ 1990/bbl $16.1 $17 $25 $25

1995 - 2020World GDP percent per annum 3.1%

Chapter 7 - Oil 85

Table 7.2 shows that world demand is projected to increase from3324 Mtoe in 1995 to 5264 Mtoe in 2020. During the period 1995 -2010, the OECD’s total demand is expected to grow at a little over1% per annum on average and then to slow after 2010. Non-OECDdemand is projected to grow strongly throughout the projectionperiod at an average rate of 2.9% per annum. The general slowdownafter 2010 results from an increase in world oil prices over the period2010 to 2015, discussed later in this chapter. During the seconddecade of the 21st century, the non-OECD countries consumption ofoil surpasses that of the OECD; by 2020 it is over 20% larger. Thenon-OECD’s increase in demand for oil is likely to be dominated bydemand growth in the Asian countries. Despite the recent economicdifficulties experienced by some Asian countries, the demand for oil inAsia is projected to grow at an average rate of around 4% per annumduring the projection period 1995-2020.

Table 7.2: BAU Projection - Total Oil Demand (Mtoe)

Transport SectorThe transport sector is projected to be the major source of oil

demand growth. The non-OECD transport sector’s demand isprojected to grow on average by 3.6% per annum throughout the

1995 2010 2020 1995-2010 1995-2020Annual Growth Rates

OECD 1832 2158.7 2261.5 1.1% 0.8%North America 873.3 1025.3 1049.9 1.1% 0.7%Europe 650.2 779.1 850.3 1.2% 1.1%Pacific 308.7 354.3 361.3 0.9% 0.6%Non-OECD 1362.9 2135.2 2793.8 3.0% 2.9%Transition Economies 274.6 329.0 390.5 1.2% 1.4%Africa 96.9 145.4 180.3 2.7% 2.5%China 163.9 355.5 505.7 5.3% 4.6%East Asia 263.9 471.5 639.1 3.9% 3.6%South Asia 98.7 191.1 277.5 4.5% 4.2%Latin America 281.5 423.8 519.7 2.8% 2.5%Middle East 183.4 218.8 280.9 1.2% 1.7%Total 3195.1 4293.9 5055.3 2.0% 1.9%

Maritime bunkers 129.2 174.7 208.7 2.0% 1.9%

World 3324.3 4468.5 5263.9 2.0% 1.9%


projection period. Growth in the OECD is somewhat lower, at anaverage of 1.5% per annum. In both cases, growth of aviation fueldemand is projected to be greater than that for surface transport.Despite its slower growth, the OECD is still projected to consumemore oil in the transport sector than the non-OECD regions in 2020.This continued dominance of the OECD reflects higher averagevehicle ownership and per capita income levels.

Table 7.3: BAU Projection - Transport Sector Oil Demand2 (Mtoe)

Power GenerationOil use in the OECD’s power generation sector is projected to

remain flat. A shift from fuel oil used in base and mid-load plantstowards middle distillates used for peaking plants is expected. Somemodest growth may occur in North America, but this is projected tobe more than offset elsewhere in the OECD3.

Power generators in Eastern Europe are expected to reduce theirannual consumption of oil by around 1% per annum on averagethroughout the projection period due to fuel substitution andincreased efficiency of use. Growth in other non-OECD countries isprojected to offset the decline in Eastern Europe, with the result that

2. Excluding maritime bunkers.3. Full details of the demand for energy in this sector can be found in Chapter 6.


OECD 992.8 1317.5 1440.4 1.9% 1.5%North America 571.5 708.7 739.9 1.4% 1.0%Europe 307.2 461.3 545.4 2.7% 2.3%Pacific 114.1 147.5 155.2 1.7% 1.2%Non-OECD 483.2 843.2 1178.5 3.8% 3.6%Transition Economies 63.7 98.5 131.2 3.0% 2.9%Africa 39.4 55.2 67.1 2.3% 2.1%China 52.2 122.8 182.4 5.9% 5.1%East Asia 94.8 205.1 312.6 5.3% 4.9%South Asia 46.3 91.9 140.6 4.7% 4.5%Latin America 130.4 202.3 260.8 3.0% 2.8%Middle East 56.4 67.3 83.9 1.2% 1.6%World 1475.9 2160.7 2619.0 2.6% 2.3%

Chapter 7 - Oil 87

oil demand in the non-OECD power generation sector is expected togrow on average by 1.7% per annum.

Table 7.4: BAU Projection - Power Generation Sector Oil Demand (Mtoe)

Stationary SectorsDemand for oil in the stationary sectors (industrial, commercial,

residential, agricultural and non-energy use) is projected to declineslightly in the OECD, but to grow by 2.6% per annum in the non-OECD. Relatively modest growth in the Transition Economies isprojected to be more than offset by rapid growth in Asia. Inconsequence, by 2020, the non-OECD region is projected to have anoil demand some 70% greater than that of the OECD. Increasingindustrialisation in the non-OECD countries, switching away fromnon-commercial fuels and greater use of oil for heating purposes in thecommercial and residential sectors explain much of this projectedgrowth in demand.

Summary of Oil DemandOne clear message from the above analysis is that the transport

sector will account for the bulk of the growth in oil demand duringthe period to 2020. Worldwide oil demand is projected to increase by1940 Mtoe between 1995 and 2020; of this growth, 59% will comefrom the transport sector, 25% from the stationary sectors, 6% from


OECD 107.2 104.3 110.7 -0.2% 0.1%North America 17.3 23.7 26.7 2.1% 1.8%Europe 46.9 42.2 45.5 -0.7% -0.1%Pacific 43.0 38.4 38.5 -0.8% -0.4%Non-OECD 200.4 263.2 307.1 1.8% 1.7%Transition Economies 62.6 50.4 49.6 -1.4% -0.9%Africa 12.8 21.2 22.2 3.4% 2.2%China 13.4 36.1 55.1 6.8% 5.8%East Asia 35.4 45.2 42.5 1.6% 0.7%South Asia 6.9 13.8 21.8 4.7% 4.7%Latin America 32.3 57.0 66.6 3.9% 2.9%Middle East 37.0 39.4 49.4 0.4% 1.2%World 307.5 367.5 417.8 1.2% 1.2%


the power generation sector and the remainder from other energyconversion industries.

Table 7.5: BAU Projection - Stationary Sectors Oil Demand (Mtoe)

Figure 7.1: BAU Projection -World Fuel Shares

The increasing concentration of oil demand in transport reflectsthe loss of share in several non-transportation sectors to other fuels,particularly to gas. Oil demand is projected to increase on average by1.9% per annum between 1995 and 2020, whereas gas is projected to

Solid Fuels Oil Gas Other

50%

40%

30%

20%

10%

0%1971 1990 1995 2000 2010 2020


OECD 643.3 638.5 610.5 -0.1% -0.2%North America 247.2 249.2 238.6 0.1% -0.1%Europe 259.8 239.2 223.1 -0.5% -0.6%Pacific 136.3 150.1 148.8 0.6% 0.4%Non-OECD 558.7 837.5 1055.8 2.7% 2.6%Transition Economies 117.2 141.9 165.2 1.3% 1.4%Africa 38.6 60.0 79.5 3.0% 2.9%China 79.8 157.4 212.9 4.6% 4.0%East Asia 113.2 183.1 230.6 3.3% 2.9%South Asia 40.6 76.0 101.6 4.3% 3.7%Latin America 93.3 126.8 145.9 2.1% 1.8%Middle East 75.9 92.3 120.1 1.3% 1.9%World 1202.0 1476.0 1666.3 1.4% 1.3%

Chapter 7 - Oil 89

grow by 2.6% per annum. Oil’s share of world energy demanddeclines from 40% in 1995 to 38% by 2020. Despite this decline, oilis projected to remain the single largest energy source. The switchfrom oil to gas can be seen in Figure 7.1.

UnitsSo far, the discussion of oil demand has been in terms of millions

of tonnes of oil equivalent. This is a unit of energy contentappropriate for analysing the substitution between fuels in energyconsumption. The data and analysis of oil production, on the otherhand, is traditionally carried out in units of millions of barrels per day(Mbd), a production rate in volumetric units. In order to link the twoanalyses, conversion factors must be applied.

Table 7.6: 1995 World Oil Demand - Oil Market Report Basis

* The figure for China appears to be too low and that for OECD Pacific appears to be too high.These figures need further investigation.

** Pending submission of the detailed historical data needed to incorporate them into the OECD,the following OECD countries are shown in the IEA Oil Market Report (until August 1998) inthe relevant non-OECD regions: the Czech Republic and Poland in Non-OECD Europe, Koreain Other Asia and Mexico in Latin America. Note also that, whereas the OMR mbd includesmarine bunkers, the IEA Mtoe does not, except for the world.

Sources: Mtoe data are taken from the IEA statistical databases and the mbd (million barrels perday) are taken from the Oil Market Report (OMR) dated 11 May 1998.

Inland AggregateDemand Bunkers Total Total Conversion

FactorMtoe Mtoe Mtoe Mbd Barrels per toe

OECD 1832.2 70.99 1903.2 40.6 7.79North America** 873.3 27.7 901.1 19.8 8.02Europe** 650.2 36.0 686.2 14.1 7.50Pacific** 308.7 7.3 316.0 6.7 7.74*Non-OECD 1362.9 58.2 1421.1 29.5 7.58Transition Economies** 274.6 1.5 276.1 6.0 7.93Africa 96.9 8.3 105.2 2.2 7.63China 163.9 2.6 166.5 3.3 7.23*Other Asia** 362.6 22.4 385.0 7.9 7.49Latin America** 281.5 8.6 290.1 6.0 7.55Middle East 183.4 14.7 198.1 4.1 7.55World 3195.1 129.2 3324.3 70.1 7.70


Two problems arise. The first is that each oil product has its ownbarrel-to-tonne oil equivalent factor, so that a change in oil productmix alters the aggregate conversion factor for a region or country. Thesecond problem is that oil consumption data and oil production dataare collected from different sources. Inevitably, some differences existbetween the data sources.

In order to deal with the above problems, the approach taken is tocompare the databases expressed in tonnes and in barrels for 1995 andto apply the resulting regional conversion factors thereafter. Thefactors used are reproduced in Table 7.6.

Using the above conversion factors, the BAU oil demandprojection is shown in Mbd terms in Table 7.7.

Table 7.7: World Oil Demand (Business as Usual)Oil Market Report Basis (Mbd)

Note: The above table excludes stock changes but includes bunkers. In 1995 there was virtuallyno change in stocks (< 0.1 Mbd).

Oil Reserves and Production4

Previous versions of the World Energy Outlook did not placegreat emphasis on distinguishing between the different types of oilsupplied to meet demand for petroleum products. The 1998 World

4. Some of the reserve estimates and charts shown in this chapter are based on work done by JeanLaherrère using the Petroconsultants database held in Geneva. The IEA would like formally to thankPetroconsultants for permission to reproduce the charts based on data taken from their database.


OECD 40.6 48.1 50.7 1.1% 0.9%North America 19.8 23.4 24.1 1.1% 0.8%Europe 14.1 17.0 18.7 1.3% 1.1%Pacific 6.7 7.7 7.9 0.9% 0.7%Non-OECD 29.5 46.0 59.9 3.0% 2.9%Transition Economies 6.0 7.2 8.5 1.2% 1.4%Africa 2.2 3.3 4.0 2.7% 2.5%China 3.3 7.1 10.1 5.3% 4.6%Other Asia 7.9 14.2 19.5 4.0% 3.7%Latin America 6.0 9.0 11.0 2.7% 2.5%Middle East 4.1 4.9 6.3 1.2% 1.7%Total Demand (excl. stocks) 70.1 94.2 111.0 2.0% 1.9%

Chapter 7 - Oil 91

Energy Outlook differs from its predecessors in this respect, becausethe projection horizon has been extended from 2010 to 2020. For thefirst time, the WEO’s oil supply projections have to consider thepossibility that the production of conventional oil could peak before2020. With this point in mind, supplies from conventional and non-conventional oil are considered separately and distinguished fromother sources of supply (see Box 7.2 at the beginning of the chapter).

Conventional Oil ReservesThe level of future conventional oil production is ultimately

determined by the quantity of remaining oil reserves and the recoveryfactor. It is therefore important that reliable estimates of remaining oilreserves are used when preparing long-term oil supply forecasts.

Perhaps the most widely used oil reserve estimates are thosepublished annually by British Petroleum (BP)5. The chart in Figure7.2, taken from the BP Statistical Review of World Energy, shows howestimates of these official world oil reserves and production havechanged during the period 1961 - 1995.

Figure 7.2: World Oil Official (proved) Reserves & Production

Source: BP Statistical Review of World Energy, 1997.

An interesting feature of Figure 7.2 is that these reserves increaseddramatically in the mid- to late -1980s. Between 1985 and 1989,worldwide oil reserves increased by 43% or 304 billion barrels, up 5. BP’s published oil reserves estimates are reproduced from the Oil and Gas Journal.

Rese

rves

- Bi

llion

Bar

rels

Proved Reserves Production

1200

1000

800

600

400

200

0

Output - Thousand Barrels per D

ay

70000

60000

50000

40000

30000

20000

10000

01961 1963 1965 1967 1969 1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995


from 708 billion barrels in 1985. During the period, total oildiscoveries amounted to approximately 65 billion barrels andcumulative production was around 91 billion barrels. Cumulativeproduction exceeded new discoveries by 26 billion barrels. This 304billion barrel increase in total reserves implies a worldwide oil reserverevision of 330 billion barrels. Such a huge increase raises thequestions of why and where these revisions occurred.

In order to answer these questions, it is useful to divide worldwideconventional oil reserves between OPEC and non-OPEC areas. InFigure 7.3, it is clear that non-OPEC proved reserves remainedbroadly stable during the period 1970 and 1995 at around 200-250billion barrels. Non-OPEC’s oil production was rising during thisperiod with new discoveries and reserve revisions increasing broadly inline with production. The bulk of the reserve revisions took place inthe OPEC area as shown in Figure 7.4.

Figure 7.3: Non-OPEC Official (proved) Oil Reserves & Production


Total OPEC official oil reserves increased by almost 300 billionbarrels between 1985 and 1989. Following the fall in the oil price in1986, OPEC’s oil production quotas became an important issue to itsmember governments. Since reserves were an important potentialfactor in determining quota allocations, every OPEC country had anincentive to increase its published reserve estimate. In the space of just

Proved Reserves Production

Rese

rves

- Bi

llion

Bar

rels

Oil Production 000 bbls/day

300

250

200

150

100

50

0

45000

40000

35000

30000

25000

20000

15000

10000

5000

01961 1963 1965 1967 1969 1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995

Chapter 7 - Oil 93

four years, total OPEC oil reserves increased by 62%. Since then,OPEC’s total oil reserves have remained virtually unchanged year afteryear.

Figure 7.4: OPEC Official (proved) Oil Reserves


Because of this large, one-off increase in OPEC’s oil reserves,many commentators have questioned the reliability of the reservesestimates data published in the BP Statistical Review of Energy andthe Oil and Gas Journal. They have noted that, while the reserveestimates are described as proven (meaning a greater than 90%probability of being produced), a comparison with thePetroconsultants oil field database suggests that large quantities ofprobable and possible reserves may have been included in the OPECestimates. Furthermore, large quantities of unconventional oil alsoappear to have been included in some OPEC member countryestimates, possibly in order to obtain a larger oil production quota.

One commentator6, Colin Campbell, has attempted to determinethe size of the over-reporting of OPEC member country reserves by

6. The Coming Oil Crisis, CJ Campbell, Multi-Science Publishing Company and PetroconsultantsS.A., Brentwood, UK, 1997.The Status of World Oil Depletion at the end of 1995, C.J. Campbell, Energy Exploration andExploitation, Volume 14, 1996, Number 1.Better Understanding Urged for Rapidly Depleting Reserves, C.J. Campbell, Oil and Gas Journal,April 7, 1997, pp 51-54.

Venezuela UAE Iran Iraq Kuwait Saudi Arabia

800

700

600

500

400

300

200

100

01960 1962 1964 1966 1968 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994

Billi

on B

arre

ls


comparing their published estimates with those obtained from thePetroconsultants’ oil field database. The results of his analysis for selectedOPEC countries and three non-OPEC countries can be seen in Table 7.8.

Given the above, it is clear that official oil reserve estimates cannotbe considered reliable indicators of remaining oil reserves. Because ofthese problems, many oil experts base their views on oil reserves on twoprincipal sources of information. The first is the Petroconsultants oilfield database, which is based in Geneva and concentrates on the worldoutside North America. The second is the United States GeologicalService (USGS), which publishes estimates of worldwide oil reserves.These two sources are not entirely independent, as the USGS estimatesare themselves partly based upon the Petroconsultants database,particularly for the world outside of North America. Despite thisinterdependence, it is not unusual for different reserve estimates to beobtained using the Petroconsultants database. For example, JeanLaherrère’s 1997 estimate of worldwide discovered reserves (1530billion barrels) differs from that of the USGS in 1997 (1608 billionbarrels). This is despite the fact that both Laherrère and the USGS usedexactly the same Petroconsultants database.

Table 7.8: Reserve Estimates by Country7 (billion barrels)

* Adjusted by Campbell to allow for years in which the published Oil and Gas Journal reserves didnot alter to reflect the fact that oil production had taken place during the previous 12 months.

7. The Status of World Oil Depletion at the end of 1995, C.J. Campbell, Energy Exploration &Exploitation, Volume 14 1996, Number 1.

World Oil Oil and Gas CampbellEstimate Journal (adjusted)* (median value) (2) - (1)

(1) (2)OPECSaudi Arabia 260.00 252.98 189.73 -63.25Iran 58.65 88.20 52.92 -35.25Iraq 99.43 97.37 68.16 -29.21Kuwait 95.20 91.74 59.63 -32.11Venezuela 64.88 63.54 31.77 -31.77Abu Dhabi 62.00 88.83 62.18 -26.65Libya 36.57 29.50 22.13 -7.37Non-OPECFormer 191.14 42.01 84.01 +42.00Soviet UnionMexico 49.78 49.78 24.89 -24.89China 30.20 17.70 28.32 +10.62

Chapter 7 - Oil 95

There are two main views on how to project future conventionaloil supply: the pessimists’ view, which makes a static assessment ofreserves, and the optimists’ view, which employs a continuous upwardreappraisal of recoverable reserves. Summaries of these views are givenbelow. Both make substantial use of the 1994 United States GeologicalSurvey (USGS) estimates. In 1994, the USGS estimated that ultimate(total recoverable) oil reserves were around 2300 billion barrels (in arange of 2100 to 2800) and included the elements shown in Table 7.9.

The two competing views on oil supply deal only withconventional oil (see Box 7.2 at the beginning of the chapter).

Table 7.9: 1994 USGS Ultimate Oil Reserve Estimate as of 1/1/1993

Source: 14th World Petroleum Congress, World Petroleum Assessment and Analysis by Charles D. Masters, EmilD. Attanasi and David H. Root, US Geological Survey, National Centre, Reston, Virginia, USA, 1994.

The Pessimists’ ViewThe pessimists treat the estimate of remaining reserves as a

snapshot of the situation today with little or no anticipation of newinformation that may become available over time, from newtechnology or from variations in the oil price. Advances in newtechnology (3D seismic analysis and horizontal drilling) are seen asincreasing the rate of production while having little impact on theestimate of recoverable reserves. Another example of how thepessimists’ view differs from that of the USGS can be found in theirestimates of undiscovered oil. The pessimists argue that the USGS’sestimates are unduly high, given that most parts of the world havealready been extensively explored. They argue that the USGSmethodology, based in part on Delphi surveys, are not reliable. Theyprefer their statistical approach that yields more conservative results.Their estimate of ultimate recoverable reserves is around 1800 billionbarrels, including cumulative production of around 800 billionbarrels, as shown in Table 7.10.

(modal estimates) Billion Barrels

Cumulative Production to date 699Remaining Identified Reserves 1103Unidentified Reserves 471Total Ultimate Recoverable Reserves 2300 (rounded)


Table 7.10: Pessimists’ View of Ultimate Oil Reserve Estimate as of 1/1/1997

Source: The Coming Oil Crisis by C.J. Campbell, Multi-Science Publishing Company &Petroconsultants S.A, page 175.

Since the purpose of this chapter is to assess oil supply, and not reserves,it is also important to note the pessimists’ view of how the stock of oil(reserves) is transformed into supply. They assume that regional or global oilproduction follows a Hubbert curve in which oil production peaks whenhalf of ultimate oil reserves has been produced. An ultimate reserve of 1800billion barrels implies that the peak in conventional oil production will occurwhen 900 billion barrels have been produced. Campbell8 has suggested thatsuch a peak could come as early as 2001. However, this date implicitlyassumes that a substantial increase in the oil price will occur once the shareof world production from swing producers (Saudi Arabia, Iran, Iraq, Kuwaitand the United Arab Emirates) reaches approximately 30%. In the absenceof such an oil price increase, the IEA’s long-term oil supply model suggeststhat even with ultimate of reserves of 1800 billion barrels, and assuming aHubbert curve, worldwide oil production would not peak until around2008 - 2009. An example of the Hubbert curve can be found in Figure 7.5.

Figure 7.5: Generalised Hubbert Curve

8. Op. Cit. 6.

OIL

PRO

DU

CTI

ON

Peak in Oil Production

TIME

Billion Barrels

Cumulative Production 784Remaining Identified Reserves 836Unidentified Reserves 180Total Ultimate Recoverable Reserves 1800

Chapter 7 - Oil 97

Improving production technologies over time could result in theright hand tail of the Hubbert curve being somewhat fatter than the lefthand tail. In addition, new technology could lead to an extension ofpeak production levels and a steeper eventual downturn in production.Thus, technical progress has the potential to change not only the areaunder the Hubbert curve, but also its shape. Part of the productionincrease in regions like the North Sea may be considered as a change inthe shape of the Hubbert curve, i.e. allowing faster depletion. While itis recognised that the Hubbert curve may not be symmetrical, trying toadjust it to allow for this asymmetry is particularly difficult. The impactof technological progress in this Outlook is therefore confined toincreasing the quantity of recoverable reserves under the Hubbert curverather than trying to estimate how it might change its shape.

The issue of the size of conventional oil reserves and the level ofproduction from them has been further complicated by a recent findingby Jean Laherrère9. Using the Petroconsultants database, he noted thatonly around 80% of oil reserves discovered are actually in production.As Figure 7.6 demonstrates, this finding holds true across all regions ofthe world. In the case of the Middle East, it is reasonable to argue that

Figure 7.6: Percentage of Discovered Oil Reserves in Production

Source: Jean Laherrère, op.cit.

9. From a paper presented by Jean Laherrère to the 11 November 1997 Oil Reserves Conferenceheld at the IEA in Paris, Distribution and Evolution of Recovery Factor. The original data for thechart were supplied by Petroconsultants.

Middle East South America Europe CIS Asia Africa

120

100

80

60

40

20

01940 1950 1960 1970 1980 1990 2000

Perc

enta

ge o

f Disc

over

ed O

il re

serv

es in

Pro

duct

ion


production has been constrained by a staged approach to thedevelopment of output to follow demand growth. It is less easy toexplain why other regions of the world are not producing at closer to100% of oil discoveries.

On the other hand, the USGS found that between 1980 and1993 there were some 925 reported discoveries10 of oil and gas towhich no reserves have been credited. Thus, whereas Laherrère’sfinding suggests that oil reserves may have been overstated, the USGSfinding suggests some underestimating of oil reserves.

The Optimists’ ViewThe optimists emphasise the roles of new information,

technological advances and higher oil prices on ultimate oil reserves.For them, the current estimate of ultimate oil reserves is treated asnothing more than inventory that can grow as uncertainty is reduced,as technology advances or as the oil price rises. They believe thatreserve growth from oil fields already discovered can occur fromupward revisions of estimates of oil in place, or from increases in therecovery factor. Where the pessimists assume that the future recoveryfactor is unlikely to increase significantly, the optimists hold that oilfields already discovered, but previously considered uneconomicbecause of their size or location, can become economic through theapplication of new technology and a higher oil price. The pessimistsdo not rule out new technology and higher oil prices making marginaloil fields economic, but argue that these fields are typically small andwould not augment reserves greatly.

Unlike the pessimists, the optimists do not assume that oilproduction follows a Hubbert curve. Indeed, the optimists say verylittle about how higher oil reserves are transformed into higher oilproduction or the date at which worldwide oil production will peak.When an explicit production assumption is made, it usually takes theform of a simple reserve to production (R/P) ratio. When the world’sdemand for oil is steadily rising, one cannot simply assume that worldproduction will remain flat and then suddenly fall to zero whenreserves are exhausted.

10. Op. cit. Table 7.9.

Chapter 7 - Oil 99

The 1998 WEO ApproachThe conventional oil supply projections described in this chapter

were prepared using the IEA’s new long-term oil-supply model. Thismodel comprises a suite of individual regional supply models, each ofwhich incorporates specific regional factors such as estimates ofcumulative production, remaining reserves and undiscovered oil. Theapproach taken here is to begin with a conservative estimate ofultimate recoverable reserves and then to increase this estimate overtime to take account of new information and the application of newtechnology. For the purposes of this analysis, Campbell’s 1996conventional ultimate oil reserve estimate of 1800 billion barrels hasbeen used as the starting point. The WEO approach to oil reserves andsupply is a synthesis of static and dynamic views, as it makes use of theextensive geological data on which the pessimists’ view is based, butpermits the estimate of proven or probable recoverable oil reserves toincrease over time. The next stage is to transform a stock estimate(ultimate recoverable reserves) into a flow (oil supply). The supplyprojections described in this chapter assume that oil productionfollows a Hubbert curve.

In order to take account of the uncertainty of ultimaterecoverable reserves, a wide range of ultimate reserve estimates hasbeen considered. The high estimates tend to be grouped around 3000billion barrels and this figure is adopted as an upper bound. The lowerbound is 2000 billion barrels. Since 1958, published ultimate oilreserve estimates have averaged 2032 billion barrels. Table 7.11indicates how the WEO’s range of 2000 - 3000 billion barrels ofultimate oil reserves is related to the pessimists’ view of 1800 billionbarrels. This range is somewhat wider than that suggested by theUSGS of 2100-2800 billion barrels. The second column in Table 7.11shows the increase from the base figure arising from additional newdiscoveries and upward revisions of identified reserves. These increasescan arise as a result of a combination between the application of newtechnologies increasing the recovery factor, the acquisition of newinformation leading in upwards oil in place and reserves in revisedestimates. The final column shows the implied recovery factor basedon a fixed stock of conventional oil in place of 6000 billion barrels, abroadly accepted current estimate.


Table 7.11: Assumed Ultimate Conventional Oil Reserves(billions of barrels)

Note: The above table treats the oil stock as being fixed at 6 trillion barrels, and all increases inultimate oil reserves as arising from improvements in the recovery factor. Identical ultimate oilreserve estimates could also be obtained if the oil stock in place were greater than 6 trillion barrels.

The range of ultimate conventional oil reserves of 2000 - 3000billion barrels means that the supply projections examined in thischapter cover a wide spectrum of reserve estimates. This range only dealswith conventional oil (see Box 7.2 at the beginning of the chapter).

Some experts11 warn that all past attempts to forecast the timingof future reserve constraints on oil production and the associated risein the world oil price have proved to be incorrect. We do not attemptto make such forecasts, but to discuss the current range of views held

Figure 7.7: Oil Supply Profiles 1996-2030 Ultimate Conventional Oil Reserves of 2300 Billion Barrels

11. The Failure of Long-Term Oil Market Forecasting, M.C. Lynch in Advances in the Economicsof Energy and Resources, Volume 8, pages 53-87, 1998.



World Oil Demand




Mill

ion

Barr

els

per D

ay

200

180

160

140

120

100

80

60

40

20

01996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Ultimate Oil Reserves Increase from base of Implied Recovery Factor 1800 billion barrels from based on a fixed oil stock in

new information and technology place of 6 trillion barrels

1800 0 30%2000 200 33%2300 500 38%3000 1200 50%

Chapter 7 - Oil 101

by experts in the field. We do not foresee any shortage of liquid fuelsbefore 2020, as reserves of unconventional oil are ample, should theproduction of conventional oil turn down. It may be that new oil discoveries,updated information on producing fields and future technology will increasethe current estimates of ultimate conventional oil reserves. We cannot knowthat now. We take the view that current evidence and analysis supports a rangeof 2 to 3 trillion barrels of these reserves. As explained above, this range alreadytakes account of estimates of undiscovered oil and growth in identified reserves.

Table 7.12: Oil Supply 1996-2020 (million barrels per day)

Notes: Identified unconventional oil refers to relatively well defined projects.Unidentified unconventional oil is from currently unknown or uncertain projects.NGLs includes some condensates.

Ultimate recoverable reserves of 1996 2010 2020 1996-20202300 Billion Barrels Annual

Growth Rate

Total Oil Demand 72.0 94.8 111.5 1.8%

Oil Supplies by SourceNatural Gas LiquidsMiddle East OPEC 1.3 2.8 3.7 4.5%World excluding Middle East OPEC 5.3 8.5 11.5 3.3%Total NGLs 6.6 11.3 15.2 3.5%

Identified Unconventional OilMiddle East OPEC 0.1 0.1 0.1 1.6%World excluding Middle East OPEC 1.2 2.4 2.4 3.0%Total Identified Unconventional Oil 1.2 2.4 2.4 3.0%

Processing Gains 1.5 2.1 2.5 2.0%

Conventional Crude OilMiddle East OPEC 17.2 40.9 45.2 4.1%World excluding Middle East OPEC 45.5 38.0 27.0 -2.2%Total Crude Oil 62.7 79.0 72.2 0.6%

World Oil Supply excluding 72.0 94.8 92.3 1.0%Unidentified Unconventional OilBalancing item:Unidentified Unconventional Oil 0.0 0.0 19.1

Total Oil Supply (excl Processing Gains)Middle East OPEC 18.5 43.8 49.0 4.1%World excluding Middle East OPEC 52.0 48.9 40.8 -1.0%World 70.5 92.7 89.9 1.0%


For the purposes of the WEO analysis, the USGS’s estimate of 2300billion barrels has been used for the BAU projection. Details of the oilproduction profile associated with ultimate reserves of 2300 billionbarrels are shown in Figure 7.7. Details are provided in Table 7.12.

OPEC Middle East is treated as the residual supplier until itsproduction begins to decline. Its conventional oil production isassumed to be capped by a maximum level of 47.9 Mbd. This ceilinghas been taken from a study published by the US Department ofEnergy in 198312 and reproduced in a recent IEA publication13. Theuse of a lower ceiling on OPEC Middle East’s production would bringforward the date at which global conventional oil production peaks,but would also lengthen the time during which OPEC Middle Eastcould remain on plateau before production went into decline.Obviously, the ability of OPEC Middle East to expand itsconventional oil production from the 1996 level of 17.2 Mbd to over40 Mbd by 2010 depends on sufficient investment in additionalcapacity, availability of capital and the willingness of producers in theregion to increase production.

Oil production outside of OPEC Middle East peaks early in thenext century in the 2300 billion barrel case. Worldwide production ofnatural gas liquids (including some condensates) is assumed to grow ataround 3% per annum. Were NGL production to grow less slowlythan assumed, then conventional oil production and eventuallyunconventional oil production would have to increase in order tobalance the oil market. Alternatively, the oil price would have toincrease in order to restrain oil demand.

The oil price is assumed to increase from $17 to $25 (1990) perbarrel (bbl) between 2010 and 2015. A ceiling of $25 bbl has beenadopted, because above this level other liquids (non-conventional oils)could become increasingly competitive with conventional oil. Thisassumed increase in the oil price from $17 to $25 bbl between 2010and 2015 is associated with the peak in conventional oil productionthat occurs around 2013 - 2014.

In this projection, Middle East OPEC conventional crude oilproduction increases its share of total oil supply from 24% in 1996 to48% in 2014 and then declines. Production of conventional crudeoutside Middle East OPEC falls as a share of total oil supply from

12. Energy Information Administration, US Department of Energy, The Petroleum Resources ofthe Middle East, May 1983.13. Middle East Oil and Gas, IEA/OECD Paris 1995.

Chapter 7 - Oil 103

63% in 1996 to 33% in 2014 and continues falling thereafter. Otheroil production (natural gas liquids, processing gains andunconventional oil production) climbs steadily from 13% of total oilsupply in 1996 to 19% in 2014 and then unconventional oilproduction expands rapidly in order to balance global demand andsupply of oil. During the period up to 2014, in which Middle EastOPEC increases its share of total oil supply, the potential fordisruptions in world oil supply increases. The extent to which OPECMiddle East countries become more dependent on international tradeand capital movements (e.g. if they become involved in downstreamoil business in oil-consuming countries) will reduce the risks of suchdisruptions. The period following the transfer from OPEC MiddleEast to unconventional oil as the source of incremental supplies couldalso be one of instability of supply. The rapid expansion ofunconventional oil production will require many multi-billion dollargreenfield production sites to come on stream. The potential clearlyexists for mismatches between world oil supply and demand becauseof the long lead times involved. It will be important for major oil-importing countries to co-ordinate their arrangements for dealingwith these supply disruptions. The IEA is already in discussions withmajor non-IEA Member countries on this subject.

Figure 7.8: Oil Supply Profiles 1996-2030Ultimate Conventional Oil Reserves of 2000 Billion Barrels



World Oil Demand




Mill

ion

Barr

els

per

Day

200

180

160

140

120

100

80

60

40

20

01996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030


The above discussion is based on ultimate conventional oilreserves of 2300 billion barrels. Reducing the level of assumedultimate oil reserves to 2000 billion barrels brings forward the date atwhich production peaks to around 2010. The oil supply productionprofile associated with ultimate conventional oil reserves of 2000billion barrels is shown in Figure 7.8.

Figure 7.9: Oil Supply Profiles 1996-2030Ultimate Conventional Oil Reserves of 3000 Billion Barrels

In the 3000 billion barrels case, oil prices are assumed to remain flatthroughout the projection period at $17 bbl and total oil demand issomewhat higher than in the 2000 and 2300 billion barrels cases, whichare based on the BAU oil demand projection. Despite the additional oildemand in the 3000 billion barrels case, the peak in oil supply is pushedback until 2020 as the higher reserves more than offsets the increase indemand. The general conclusion is that conventional oil production islikely to peak sometime between 2010 and 2020.

The range of 2000-3000 billion barrels of ultimate recoverablereserves of conventional oil provides a guide to the range ofuncertainty currently expressed by experts. This Outlook, in commonwith those oil companies we have consulted, sees no shortage of oilsupply. Yet it draws attention to the likely change from conventionalto unconventional oil at the margin of oil supply between 2010 and2020 and a possible increase in the oil price.



World Oil Demand




Mill

ion

Barr

els

per

Day

200

180

160

140

120

100

80

60

40

20

01996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Chapter 7 - Oil 105

Increases in Estimates of Recoverable Reserves

Table 7.13: North Sea Oil Fields’ Recoverable Oil Reserves14

Source: UK Brown Book various annual editions, see for example Oil and Gas Resources of theUnited Kingdom, The Energy Report, Volume 2, 1998, Department of Trade and Industry, HMSO,London, 1998.

14. The UK Department of Trade and Industry has also examined the North sea’s recovery factors, seeEstimation of ultimate recovery of UK oil fields; the results of the DTI questionnaire and a historical analysis,J.M. Thomas, Petroleum Geoscience, Vol. 4, 1998, pp. 157-163. The paper compares reserve estimatesfor 1996 and 1998 and reaches less optimistic conclusions. It suggests that a large part of the reserveincrease can be explained by exceptional circumstances not related to technological improvements, butto an initial underestimation of the efficiency of the water drive in North Sea’s sandy reservoirs.In Geoscore: a method of quantifying uncertainty in field reserve estimates, Dromgoole, P. and Speers R.Geoscience 3, 1997, the authors found that over a four-year period, low-complexity fields areunderestimated by 20%, medium-complexity fields overestimated by 10% and higher-complexity fieldsoverestimated by 15%. The paper also notes that most fields exhibited reserve growth in later life.

Million Tonnes of OilOriginal Brown 1996 Brown Difference Block OriginalBook Estimate Book Brown

Estimate Book

Auk (P+) 8 17 +9 30/16 1977Beatrice 21 21 0 11/30a 1979Beryl A (P+) 70 102 +32 9/13 1977Brent (P+) 230 270 +40 211/29 1977Buchan 7 16 +9 21/1 1979Claymore 57 77 +20 14/19 1977Cormorant South (P+) 20 29 +9 211/26 1977Cormorant North (P+) 55 63 +8 211/21a 1980Dunlin 80 55 -25 211/23 1977Forties 240 334 +94 21/10 1977Fulmar (P+) 70 74 +4 30/16 1979Heather 20 14 -6 2/5 1977Hutton North West 38 16 -22 211/27 1980Magnus 60 106 +46 211/12a 1979Maureen 21 29 +8 16/29 1979Montrose 20 13 -7 22/17 1977Murchison 51 46 -5 211/19 1979Ninian 140 157 +17 3/3 1977Piper 85 136 +51 15/17 1977Statfjord 412 522 +110 211/24 1979Tartan 2 14 +12 15/16 1979Thistle 76 55 -21 211/18 1977

Totals 1782 2167 +384


As noted above, the differences between ultimate oil reservesestimates arise from different assumptions about the impact of newinformation and technology developments. Unfortunately, obtainingreliable data on which to estimate this impact is not an easy task. Somedata are available for the North Sea. Table 7.13 compares the 1996estimates of recoverable oil reserves for 22 old North Sea oil fields withtheir estimated recoverable oil reserves in the late 1970s.

Table 7.13 shows that the total quantity of recoverable oil from the22 oil fields examined increased by 22% in the space of less than 20 years.Total recoverable oil reserves from these fields therefore increased onaverage by around 1% per annum. Even this is an underestimate, as for sixof the fields (indicated by a P+) the late 1970s recoverable oil estimateincluded more than just proven and probable recoverable oil reserves.

If the increase in recoverable reserves of 1% per annum held trueelsewhere in the oil industry, then, assuming an initial recovery factor of30%, the recovery factor could increase by 0.3 percentage points perannum15. Over the space of 25 years (1995-2020) this would increase thetypical recovery factor from 30% to 38%. This would imply an increase inrecoverable reserves of 500 billion barrels if the starting recovery factor of30% were applied to a resource base of 6000 billion barrels (6000 x 0.3 =reserves of 1800 billion barrels).

The ultimate oil reserves range of 2000-3000 billion barrels used inthis chapter is equivalent to a range in the recovery factors of 33% - 50%,assuming a certain resource base of 6000 billion barrels. Thus, if the oilresource base was 6000 Gb and ultimate reserves were to increase from2000 to 3000 billion barrels, the recovery factor would have to increase by17 percentage points, or 0.68 percentage points per annum, over a 25 yearperiod. This increase is more than double that observed in the North Sea,according to the above table.

Another interesting approach is that of Jean Laherrère16 using thePetroconsultants database. He compared recovery factor estimates preparedby Roadifer17 for 300 giant fields in 1987 with his own estimates for 200fields using Petroconsultants data for 1996. Figure 7.10 illustrates thedistribution of recovery factors across oil fields in the two years. Between1987 and 1996 virtually the whole giant oil field distribution moved to theright, indicating a general improvement in the recovery factor.

15. Work done by Jean Laherrère using the Petroconsultants database found some evidence of animprovement in recovery factors for large oil fields, but little or none for small fields. 16. Jean Laherrère, op. cit.17. Roadifer R.E, 1987 Size distributions of the World’s largest known oil and tar accumulations,AAPG studies in geology #25, pages 3 - 23.

Chapter 7 - Oil 107

Using data from Figure 7.10, it has been calculated that theaverage recovery factor for Roadifer’s 1987 sample of 300 giantoilfields was 33.3%, compared to 38.6% for Laherrère’s 1996 sampleof 200 giant oilfields. This analysis suggests that the average giantoilfield’s recovery factor increased by 5.3 percentage points in thespace of nine years, or 0.6 percentage points per annum. In theunlikely event that giant oilfields’ recovery factors were to continue toincrease at 0.6 percentage points per annum, then by the year 2020the average recovery factor would be some 14.2 percentage pointshigher than in 1996. The average giant oilfield in 2020 wouldtherefore have an average recovery factor of 52.8%.

Figure 7.10: World outside North America: Giant Oil FieldsRecovery Factor Distributions 1996-1987

One criticism of this analysis is that it is based on two differentsets of giant oil fields18. While this criticism undoubtedly has somevalidity, the sample sizes are sufficiently large for there to be

Recovery Factor %

200 Giants 1996 (Laherrère) 300 Giants 1987 (Roadifer)

100

80

60

40

20

0

Perc

enta

ge o

f Oilf

ield

s w

ith a

Rec

over

y Fa

ctor

less

than

0 10 20 30 40 50 60 70 80 90

18 In discussions with the IEA about this comparison Jean Laherrère has made the point that thecomparison is between two different distributions of fields. Each distribution therefore containsdifferent fields and one is not directly therefore comparing like with like. Figure 7.10 was preparedby the IEA using data supplied by Jean Laherrère and the IEA therefore assumes full responsibilityfor Figure 7.10.


considerable overlap between them. Put simply, Figure 7.10 showsevidence of giant oil fields’ recovery factors improving during the period 1987 - 1996. It may not be possible to extrapolate this resultto all fields, see notes on Thomas and Dromgoole et al in reference toTable 7.13.

An alternative interpretation of the range 2000-3000 billionbarrels for ultimate reserves of conventional oil is given in Box 7.3.

Box 7.3: Alternative Explanation of the Range in EstimatedUltimate Oil Reserves

An alternative explanation of the range in estimated ultimateoil reserves highlights growth factors applied to known oil fields.It argues that new discoveries will not contribute greatly toincreases in ultimate reserves because the evolution of discoverystatistics show that the pace of discovery is slow and the futurepotential for them is not large. The evolution of technology isrecognized, but it is difficult to assess to what extent it simplyaccelerates depletion without extending reserves. The maindeterminant of the growth factor in oil reserve estimates is seen asarising from reassessment of the reserve sizes of individual knownfields as new information becomes available and confidence builds.The wide range of high reserve estimates with low probability isusually ignored in preparing reserve estimates early in the life of anoil field. But it is taken into account as experience is gained lateron. The size of the growth factor depends on two factors. The firstis the rules governing declarations of reserve estimates which arefor “proven” reserves in the United States, for “proven” and“probable” elsewhere. The second is the degree of riskiness andcomplexity of the field, since oil companies are likely to be morecautious in risky situations, leaving less room for upward revisionlater on. Indicative values of growth factors are:

• an initial US onshore proven barrel of oil grows to 6 ultimatereserve barrels;

• an initial US offshore proven barrel grows to 4 ultimate reservebarrels;

• an initial non-US probable barrel grows to 2 ultimate reservebarrels.

For a lower boundary, it is assumed that half the reserves (thelargest fields) will grow by a factor of 2 and the other half will notgrow at all, giving an average growth factor of 1.5. An averageupper boundary growth factor is taken as 2, higher for the largerfields and lower for the others. These factors may be applied to thenumbers in Table 7.10 to arrive at an alternative interpretation ofthe range of 2000-3000 billions barrels of ultimate conventionaloil reserves. At the lower boundary, future discoveries ofconventional oil just make up for overestimates of identifiedreserves and at the upper boundary unassessed identified reservesand future discoveries are taken as 300 billion barrels, larger thanthe 180 figure given in Table 7.10. The two bounds are calculatedbelow:

Billion BarrelsLower BoundaryCumulative reserves 784Remaining identified andunidentified reserves 836Growth in remaining and unidentified reserves @ 50% 418

2038Upper BoundaryCumulative reserves 784Remaining identified andunidentified reserves 1136Growth in remaining and unidentified reserves @ 100% 1136

3056

In this type of distribution, the expected (or mean) value ofrecoverable reserves is greater than the most likely (or modal)value. A range of uncertainty may be quoted for the size of thefield, where 5 per cent of the probability lies below the“reasonable” minimum value and another 5 per cent lies above the“reasonable” maximum value. Early in the life of the field,insufficient weight is given to the higher reserve estimates. Onaverage, as production flows and information is gathered on the

Chapter 7 - Oil 109

characteristics of the field, the range of uncertainty narrowstowards the expected value. This new information and increasedconfidence in the size of the reserves explains a major part of thegrowth in reserve estimates of existing fields.

Box 7.4: Uncertainty of Reserve Estimates

The probability distribution of the total recoverable oil in afield is typically a log-normal curve - it has a long tail, as shownbelow.

Unconventional Oil ReservesThe definition of unconventional oil used in this study is given in

Box 7.2 at the beginning of this chapter. While some commentatorsargue that deep offshore oil should be classified as unconventionalbecause of the difficulties of extraction, others note that substantialquantities of deep offshore oil are currently being produced and thisoil should therefore be classified as conventional. Less contentious are


Probability

Most LikelyValue

ExpectedValue

A B Recoverable Reserves

90%

5%5%

A = "Reasonable Minimum"B = "Reasonable Maximum"

Chapter 7 - Oil 111

the tar sands of Canada and Venezuela or the oil shales of the UnitedStates. A recent study of unconventional resources produced theestimates shown in Table 7.14.

Table 7.14: Conventional and Unconventional19 Oil Reserve Estimates

Source: The World’s Non-Conventional Oil and Gas, Hydrocarbons of last recourse, A. Perrondon,J.H. Laherrère and C.J. Campbell, published by the Petroleum Economist, March 1998, page 98.Note that the yet-to-produce estimates include undiscovered oil.

Based on the above estimates and their own definition ofunconventional oil, Perrondon et al project production ofunconventional oil to be 5.5 Mbd in 2000, 8 Mbd in 2010 and 11Mbd in 2025. Unconventional oil production in each year isprojected to be equally divided between extra-heavy oil/bitumen andultra-deep-water and polar oil. This represents a conservativeestimate of unconventional oil reserves based on a narrowerdefinition of conventional oil and a wider definition ofunconventional oil than those used in this study.

The United States Department of Energy’s Energy InformationAdministration (USDOE/EIA) is more optimistic than Perrodon inits prospects for unconventional oil. The USDOE notes that theresource base could be at least 5 trillion barrels, only part of whichcould actually be produced, and that as much as 15 Mbd couldbecome available by 2020. This assumes that the world oil price risesto $25 per barrel early in the 21st century20. In an earlierpublication21 the USDOE noted that, with current technology,

Billion Barrels Ultimate Undiscovered Yet-to-Produce

Conventional Oil 1700 - 1800 - 2300 200 1000Conventional Gas Liquids 200 - 250 - 400 50 200Unconventional Oil 300 - 700 - 2000 100 700

Total 2300 - 2750 - 4000 350 1500 - 1900 - 3500

19. The Perrondon et al study defines conventional oil as having an API of greater than 10° andresiding in water depths of less than 1000 metres. All oil not satisfying at least one of these twocriteria is classified as unconventional. 20. International Energy Outlook 1998, With Projections Through 2020, USDOE/EIA, April 1998,DOE/EIA - 0484(98), page 38.21. International Energy Outlook 1997, With Projections to 2015, April 1997 DOE/EIA - 0484(97), page 37.

around 550 billion barrels of unconventional oil could be producedat a cost of $30 per barrel or less. With significant technologicaladvances, approximately 2 trillion barrels of unconventional oilcould become economic to produce by 2020 at a cost of $30 perbarrel. The USDOE thus envisages unconventional oil resourceslying in the range of 550-2000 billion barrels between now and2020. It should be noted that 2000 billion barrels is similar inmagnitude to the USGS’ estimate of ultimate conventional oil (2300billion barrels). Unlike conventional oil, very little unconventionaloil has been produced to date.

One interesting unconventional oil source is gas-to-liquids(GTL) technology. GTL was first developed in 1923, but has onlyrecently come of age. Recent cost reductions mean that GTL couldbe on the verge of being economic. GTL is important as there arean estimated 1488 trillion cubic feet (tcf ) of gas finds, each at least5 tcf, that cannot be marketed because of their geographicallocation. This “stranded gas” is too far from existing pipeline grids orLNG liquefaction plants for it to be economic to use, but if the gascould be converted into liquid via GTL it could be transported tomarket in tankers. Converting the 1488 tcf of stranded gas intoliquids via GTL would produce the equivalent of 150 billion barrelsof oil. This is a large quantity and is broadly similar in size to somereserve estimates for the Caspian Sea.

A crucial factor in determining the future production ofunconventional oil is its production cost. Table 7.15 presents costinformation (IEA Secretariat estimates) for existing or likely projectsbefore 2005. Note that this cost information is unlikely to apply toall of the unconventional oil recoverable reserves in a region, sincethe cheaper reserves are invariably produced first and the moreexpensive reserves later in a province’s lifetime.

All of these estimates are at or below average world crude oilprices and refer to projects likely to enter into production before2005. The IEA projections of oil supply described earlier envisage avery rapid expansion of non-conventional supplies following a peakin production of conventional oil in the period 2010 to 2020. Theimpact of rapid expansion of large scale non-conventional oilproduction facilities on unit costs is unknown, but might be higherthan for the current, relatively small scale activities. To allow for thepossibility of higher production costs, the world oil price has beenincreased from $17 to $25 (1990 prices) over the period 2010-2015


Chapter 7 - Oil 113

in the BAU projection. In practice, advances in technology may welllimit the extent of such a price rise. On the other hand, morestringent environmental controls in the future could increase it.There is inevitably uncertainty on this issue.

Table 7.15: Production Cost Estimates

Note: Cost data are only for those projects likely to enter into production before 2005.

All of these estimates are at or below average world crude oilprices and refer to projects likely to enter into production before2005. The IEA projections of oil supply described earlier envisage avery rapid expansion of non-conventional supplies following a peakin production of conventional oil in the period 2010 to 2020. Theimpact of rapid expansion of large scale non-conventional oilproduction facilities on unit costs is unknown, but might be higherthan for the current, relatively small scale activities. To allow for thepossibility of higher production costs, the world oil price has beenincreased from $17 to $25 (1990 prices) over the period 2010-2015in the BAU projection. In practice, advances in technology may welllimit the extent of such a price rise. On the other hand, morestringent environmental controls in the future could increase it.

Generally Accepted Unconventional Oil ProjectsOperating Capital cost Total Costs Recoverable

cost contribution $/bbl Reserves$/bbl $/bbl (billion barrels)

Canada Alberta Oil Sands 9 - 10 3 - 5 12 - 15 300Venezuela Orinoco 8 - 10 5 - 7 15 - 17 300Gas to Liquids >18 150

Other Unconventional / Conventional Oil ProjectsOperating cost Capital cost Total Costs

$/bbl $/bbl contribution $/bbl

California Heavy Crude Oil (EOR) 5 - 9 2.5 - 3 7.5 - 12Western Canada Heavy Crude Oil (EOR) 3 - 5 2.5 - 3 5.5 - 8Mexico Heavy Crude Oil 1 5 - 6 6 - 7US Gulf of Mexico Deepwater (>200 metres) 3 3.5 - 5.5 6.5 - 8.5Brazil Offshore Deepwater (>200 metres) 3.5 1.5 - 4 5 - 7.5Alaskan Oil 3.5 - 4.5 2 - 3 5.5 - 7.5US Stripper Wells 6 - 16 n.a. 6 - 16


Tabl

e 7.

16:

Iden

tifi

ed U

ncon

vent

iona

l Oil

Supp

ly -

Tho

usan

d B

arre

ls p

er D

ay

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

Ven

ezue

la T

otal

3672

103

123

235

330

415

620

705

790

900

Ori

noco

Upg

radi

ng J

oint

Ven

ture

s13

100

170

230

410

470

530

615

Ori

mul

sion

3672

103

110

135

160

185

210

235

260

285

Can

ada:

Syn

thet

ic C

rude

Tot

al28

127

928

731

133

536

543

552

054

557

059

5

Sync

rude

205

201

209

219

235

260

285

310

335

360

385

Sunc

or76

7878

9210

010

515

021

021

021

021

0

US:

Oth

er H

ydro

carb

ons T

otal

306

301

341

345

349

353

357

361

365

369

373

Bra

zil:

Alc

ohol

s Tot

al21

924

726

227

628

028

028

028

028

028

028

0

Sout

h A

fric

a: T

otal

195

190

185

180

175

170

165

160

155

150

150

Saso

l15

015

015

015

015

015

015

015

015

015

015

0

Mos

sgas

4540

3530

2520

1510

50

0

Res

t of

Wor

ld10

412

111

310

210

210

211

212

413

714

714

7

Wor

ld11

4112

1012

9113

3714

7616

0017

6420

6521

8723

0624

45

Chapter 7 - Oil 115

There is inevitably uncertainty on this issue. The role of unconventional oil in the WEO projections is to act

as the residual producer once OPEC Middle East is no longer able tofulfil this role. Thus, once global conventional oil production peaks,all additional oil demand is sourced from unconventional oilreserves. Estimated identified unconventional oil production for theperiod 1995 - 2005 is shown in Table 7.16.

Net Oil Imports and Stocks22

Oil companies hold oil stocks equivalent to around 55-65 daysof consumption for operational purposes. IEA member countriesare required to hold emergency oil stocks equivalent to at least 90days of net imports. A number of European IEA Member countrieshold stocks in excess of this minimum to meet European Union(EU) obligations to hold stocks equivalent to 90 days of oilconsumption. Some IEA Member governments hold strategic stocksin addition to the stocks held by oil companies. Although Canadaand Norway are net oil exporters, they also hold oil stocks. Detailsof IEA oil emergency measures, including stockholding obligations,may be found in relevant IEA publications23. The oil supplyprojections in this chapter point to increasing reliance by oil-importing countries on Middle East producers in the first decade ofthe next century. For this reason, consuming countries may wish toincrease their stockholdings. There are many uncertain factors atwork, and trying to project future OECD stocks is a difficult task.For the purposes of these projections, it has been assumed that theOECD’s regional oil stocks (as of the end of 1997) rise at the samerate as net oil imports.

Outside of the IEA, most countries do not yet have any formalpolicy for maintaining strategic oil stocks. Historical data on non-OECD oil stocks are poor and so projecting non-OECD oil stocks iseven more difficult than for the OECD countries. The assumptionmade in these projections is that the non-OECD regions hold oilstocks equivalent to 55 days of oil consumption. This assumption isalso applied to the base year 1997 in order to provide a starting pointfor the oil stock projections.

To summarise:

22. For projection purposes, oil is assumed to include both conventional and unconventional oil.23. Oil Supply Security: The Emergency Response Potential of IEA Countries, IEA/OECD Paris, 1995.


• OECD stocks are assumed to rise at the same rate as netimports;

• non-OECD stocks are assumed to be equal to 55 days of oilconsumption.

Changes in estimates of oil stocks from one year to the next areincluded in Table 7.18 as an element of oil demand.

Table 7.17: Oil Stocks (million barrels)

Note: OECD data are for total stocks on land. IEA Oil Market Report, 11th May 1998, Table 7.They include oil in pipelines and other operational stocks that are excluded from data in IEAstatistical publications. Non-OECD stock data were obtained by multiplying the oil demand datafor 1997 shown in Table 1 of the IEA’s Oil Market Report (11th May 1998) by 55 days.* Excluding Mexico.** Including Mexico.

Table 7.18 presents the net import position for each of theWEO’s regions. Since, by definition, the source of the unidentifiedunconventional oil is unknown, it is not possible to include this oil inthe net import calculations. Since most of the world’s unconventionaloil reserves are situated in the Americas, particularly Canada andVenezuela, the net import positions of OECD North America andLatin America are likely to be lower by 2020 than the above tablesuggests.

End 1997 2010 2020

Total OECD 3708.0 5710.5 6421.2

OECD North America* 1724.2 2666.3 2763.8OECD Europe 1248.1 2165.5 2749.0OECD Pacific 735.8 878.8 908.4

Total Non-OECD 1749.0 2516.1 3277.2

Transition Economies 313.5 395.7 469.7Africa 126.5 180.0 222.7China 220.0 391.4 555.8Other Asia 495.0 782.0 1075.2Latin America** 363.0 495.3 607.1Middle East 231.0 271.7 346.7

World 5457.0 8226.6 9698.4

Chapter 7 - Oil 117

Dem

and

Supp

lyN

etD

eman

dSu

pply

Net

Dem

and

Supp

lyN

etIm

ports

Impo

rtsIm

ports

1996

1996

1996

2010

2010

2010

2020

2020

2020

OEC

D N

orth

Am

eric

a20

.311

.19.

323

.48.

614

.824

.18.

915

.1O

ECD

Eur

ope

14.4

6.7

7.7

17.0

4.5

12.5

18.7

2.8

15.9

OEC

D P

acifi

c6.

70.

76.

07.

70.

37.

47.

90.

37.

6To

tal O

ECD

41.4

18.4

23.0

48.1

13.4

34.7

50.7

12.0

38.7

Tran

sitio

n Ec

onom

ies

5.5

7.3

-1.8

7.2

10.2

-3.0

8.5

9.4

-0.9

Afri

ca2.

27.

7-5

.53.

37.

8-4

.64.

06.

3-2

.2C

hina

3.6

3.1

0.5

7.1

3.2

3.9

10.1

2.0

8.1

Oth

er A

sia8.

53.

74.

814

.22.

911

.319

.52.

417

.2La

tin A

mer

ica

6.3

9.8

-3.5

9.0

10.4

-1.4

11.0

8.6

2.5

Mid

dle

East

4.1

20.4

-16.

34.

944

.7-3

9.7

6.3

49.2

-42.

9To

tal N

on-O

ECD

30.4

52.1

-21.

946

.079

.3-3

3.4

59.9

77.9

-18.

0W

orld

Con

vent

iona

l, Id

entif

ied U

ncon

vent

iona

lan

d N

GLs

exclu

ding

stoc

k ch

ange

s.71

.770

.51.

194

.292

.71.

511

1.1

89.9

21.1

Uni

dent

ified

Unc

onve

ntio

nal O

il0.

00.

019

.1Pr

oces

sing

Gai

ns1.

52.

12.

5St

ock

Cha

nge

0.3

0.6

0.4

Wor

ld72

.072

.00.

094

.894

.80.

011

1.5

92.4

19.1

Tabl

e 7.

18:

Oil

Dem

and,

Sup

ply

and

Net

Im

port

sC

onve

ntio

nal O

il R

eser

ves

of 2

300

Bill

ion

Bar

rels

- B

AU

Pro

ject

ion

(mill

ion

barr

els

per

day)

Not

e: T

he W

orld

Ene

rgy

Mod

el’s

proj

ecti

ons

are

base

d on

the

Mto

e st

atis

tics

sho

wn

in t

he I

EA

sta

tist

ical

pub

licat

ions

. Ine

vita

bly,

the

re a

re s

ome

diff

eren

ces

betw

een

that

dat

abas

e an

d th

e se

para

te O

il M

arke

t Rep

ortd

atab

ase

whi

ch u

ses

mill

ion

of b

arre

ls p

er d

ay (

Mbd

) as

its

unit

of

mea

sure

men

t. In

ord

er t

o de

alw

ith

this

pro

blem

the

Mto

e da

ta h

as b

een

conv

erte

d to

mbd

usi

ng r

egio

nal c

onve

rsio

n fa

ctor

s; t

hese

wer

e di

scus

sed

earl

ier

in t

he c

hapt

er. B

ecau

se o

f th

ese

conv

ersi

on d

iffic

ultie

s, th

ere

are

som

etim

es s

mal

l diff

eren

ces

betw

een

the

sum

of t

he r

egio

ns a

nd th

e w

orld

tota

ls.So

urce

: 199

6 su

pply

and

dem

and

data

take

n fr

om th

e M

ay 1

998

Oil

Mar

ket R

epor

t,ta

bles

1 a

nd 4

.


The following table shows how the OECD’s oil dependence (i.e.net imports as a percentage of oil demand) is projected to rise duringthe period to 2020. After peaking early in the next century, OECDEurope’s conventional oil production is projected to decline. Thisresults in the region’s net import position worsening considerably. TheOECD will become increasingly dependent on OPEC Middle Eastuntil conventional oil production in that region peaks around2013/2014. Beyond that date, the OECD will need increasingly toderive its supplies of oil from unconventional sources.

Table 7.19: Oil Import Dependence (per cent)

Note: These figures exclude stock changes, processing gains and unidentified unconventional oil.

Table 7.19 includes NGLs. Since worldwide demand for gas isprojected to grow on average by 2.6% per annum in the BAU case, itis expected that considerable quantities of associated liquids (NGLsand condensates, etc.) will be produced with this gas. Since worldwidegas production is not expected to peak until well after 2020,production of associated liquids from gas production is also unlikelyto peak until then. In some regions of the world, declining gasproduction will reduce the production of NGLs, and so in practicethere is likely to be considerable regional variation in NGLproduction. On the other hand, use of gas-to-liquids technology couldresult in liquids production from gas reservoirs increasing at a fasterrate than gas demand. In view of these difficulties, trying to be preciseabout the likely net import position of the OECD during theprojection period is particularly difficult, especially after 2010. Onestrong conclusion is that the OECD’s net import requirement will riseduring the projection period. Whether market forces result in theOECD’s meeting additional oil demand via imports from OPECMiddle East or by increasing unconventional oil production will haveimportant consequences for the future energy security of the OECD.

1996 2010 2020

OECD North America 45 63 63OECD Europe 53 74 85OECD Pacific 90 96 96Total OECD 56 72 76

Chapter 7 - Oil 119

Oil Supply Projection ComparisonsThe only other major organisation that regularly publishes a long-

term world oil supply projection is the United States Department ofEnergy24. It adopts a somewhat different approach and does notdistinguish explicitly between conventional and unconventionalsources of oil.

Table 7.20: Oil Supply USDOE / EIA - Reference Case(million barrels per day)

Note: The above table includes all sources of oil, e.g. NGLs, processing gains, unconventional andconventional oils.

Although the total oil supply projections in the two cases are verysimilar, the disaggregation is very different. In the IEA’s projection,production of conventional oil from the world excluding Middle EastOPEC peaks early in the 21st century; in the USDOE’s projection itcontinues to grow throughout the projection period. One regionwhere there are considerable differences between the two projections isEurope. In 2010, the USDOE’s supply projection for Western Europeis some 3 mbd higher than this Outlook’s projection for OECDEurope (7.5 versus 4.5 Mbd). By 2020, the difference expands to 3.5Mbd (6.3 versus 2.8 Mbd). A 1996 IEA study25 indicated that theUK’s offshore oil production from currently known fields would peakduring 1999 and then go into decline. Given this projection, and thelikely peaking of Norwegian offshore production early in the followingdecade, the USDOE’s projection appears very optimistic. A similarquestion arises with respect to North American production (excludingMexico). The USDOE projects oil supply to be virtually flatthroughout the period, while the IEA projects supply to fall. In 2020,the IEA projects that North American oil production will be 8.9 mbdcompared to the USDOE’s projection of 11.9 Mbd.

1996 2010 2020

Middle East OPEC 18.5 27.2 47.3World excl. Middle East OPEC 53.5 59.0 68.6World 71.8 95.5 115.9

24. USDOE/EIA, International Energy Outlook 1998 - With Projections Through 2020, page 179.25. Global Offshore Oil Prospects to 2000, IEA/OECD 1996.


Table 7.21: Oil Supply IEA WEO 1998 - BAU(million barrels per day)

When examining the two oil supply projections, it is important toremember that in the IEA’s Outlook projection there is an explicit linkbetween oil production and reserves in the form of the Hubbert curve.This is an important difference, as the USDOE projection appears toassume that continuing improvements in technology will allow oilreserves and oil production to increase without an explicit linkbetween them. In the USDOE’s projections, only two producers (USand Western Europe) are projected to have lower oil production in2020 than in 1996. Even these declines are very modest, just 0.9 and0.7 Mbd respectively over a period of 24 years.

Great uncertainties exist for the Transition Economies. The IEAprojection shows supply from this region increasing from 7.3 Mbd in1996 to 10.2 Mbd and then declining to 9.4 Mbd by 2020. TheUSDOE projection, by contrast, shows a continual increase inproduction to 13.2 Mbd in 2020. This region includes the CaspianSea and Russia. Russia is a mature production province and theCaspian Sea an emerging one. In recent years, FSU oil production hasbeen depressed by a lack of investment, particularly in existing Russianoilfields, and there have been considerable difficulties in bringing theCaspian Sea’s oil reserves to market. Trying to project how productionfrom either of these two provinces will develop during the next 20years is a task fraught with difficulties. Combining production fromboth provinces into a single Transition Economies projection furthercompounds these difficulties. It is therefore too early to say whether theIEA or USDOE’s projection is likely to prove more accurate in 2020.

2300 Gb Conventional 1996 2010 2020Oil Reserves

Conventional & NGLsMiddle East OPEC 18.5 43.7 48.9World excluding Middle East OPEC 50.8 46.5 38.5Sub-Total 69.3 90.2 87.4

Unconventional Oil 1.3 2.4 21.5Processing Gains 1.5 2.1 2.5Sub-Total 2.8 4.5 24.0

Total 72.0 94.8 111.5

Chapter 7 - Oil 121

In summary, the USDOE oil supply projections are considerablymore optimistic than the BAU projection (based on 2300 billionbarrels conventional oil reserves). One major reason for the differenceis the absence of an explicit quantitative link in the USDOE’sprojection between production and reserves. At some point in thefuture, worldwide conventional oil production must peak, just as itdid in the United States, for example. Worldwide conventional oilproduction cannot rise year after year and then rapidly fall to zerowhen reserves are exhausted. It seems more likely that conventionaloil production will decline gradually during the post-peak period.Considerable uncertainties remain, on current estimates of recoverablereserves of conventional oil, on the likely impacts of new technologies,and on the costs of unconventional oil supplies when they arerequired. One purpose of this chapter has been to highlight theseuncertainties.

Chapter 8 - Gas 123

CHAPTER 8GAS

Box 8.1: Gas Supply

The demand for gas is growing rapidly worldwide. Where gas isavailable and the delivery system to the market is in place, or can bebuilt, gas is the preferred fuel for power generation, heating inbuildings and in industrial applications. Once the substantial capitalinvestments in gas delivery systems have been made, the marginal costof delivering gas in the short term is low, provided spare capacity todeliver exists. Hence demand will be encouraged until full capacity isreached. On a long-term basis, demand will only grow if gas prices aresufficient to cover the full costs of delivering additional gas and thenecessary supply infrastructure. Price signals1 will identify bottlenecksin the gas chain and must be strong enough to attract the investmentneeded to overcome them. In practice, the limiting factors on thegrowth in gas consumption will vary from region to region. Theyinclude the size and cost of indigenous gas reserves, the distance fromexporting countries, competition from competing fuels (especially coalin North America and China) and the size of the local energy market.

This chapter presents the business as usual (BAU) gas demandand supply projections.

Gas DemandTable 8.1 shows that over the period 1995 - 2020, worldwide gas

demand is projected to grow at an average annual rate of 2.6%. Non-OECD demand is projected to grow more quickly, at 3.5% perannum, and OECD gas demand more slowly, at 1.7% per annum.Rapidly expanding non-OECD gas demand is 40% larger thanOECD gas demand by 2020.

Total Final ConsumptionOne reason why the OECD’s gas demand is expected to grow

more slowly than in the rest of the world is saturation of gas demandin several sectors. The share of gas in most OECD final consumptionsectors is already high. For example, in 1995 the share of gas in total

1. Natural Gas Pricing in a Competitive Environment, IEA/OECD Paris (forthcoming).

124 World Energy Outlook

Table 8.1: Total Primary Energy Supply of Gas (Mtoe)

Note : OECD North America in the above table excludes Mexico, which is included in LatinAmerica. 1 tcf = 23.31 Mtoe

fossil fuel consumption in the stationary sectors was 43%. Historically,much of the growth in gas demand has come from fossil fuel switchingin the residential, commercial, public administration and industrialsectors. In these sectors taken together, the share of gas in total fossilfuel consumption had reached 57% by 1995. Considerable scope forswitching away from other fossil fuels to gas still exists: oil demand inthe industrial sector still exceeds that of gas, for example. But thecontribution of fuel switching to the future growth in gas demand islikely to be more modest than in the past. Saturation in some end-uses, particularly the residential sector’s space and water heating, is alsolikely to limit the future rate of growth in OECD gas demand. InNorth America, a higher gas price will tend to switch gas use fromindustrial boilers to combined-cycle gas turbines for power generation.

It is not surprising, then, that the OECD’s total final consumptionof gas is projected, as shown in Table 8.2, to be virtually flat during theprojection period, growing at an annual average rate of just 0.2%.Elsewhere, the share of gas in total final consumption of fossil fuels wasjust 18% in 1995, compared to 26% in the OECD, and so thepotential for fuel switching to gas is greater. Furthermore, per capitaenergy consumption is typically lower in the non-OECD regions andso the saturation of some end-uses is less of a restraining factor. When

1995 2010 2020 1995 - 2020Annual

Growth Rate

OECD 949.8 1329.5 1433.4 1.7%North America 575.9 704.6 676.2 0.6%Europe 301.3 506.1 625.2 3.0%Pacific 72.7 118.8 132.0 2.4%Non-OECD 860.6 1391.6 2034.9 3.5%Transition Economies 498.3 646.7 835.2 2.1%Africa 39.2 70.5 102.2 3.9%China 16.7 56.6 80.7 6.5%East Asia 75.8 178.8 289.5 5.5%South Asia 33.7 89.9 160.4 6.4%Latin America 92.7 185.1 306.0 4.9%Middle East 104.3 164.2 261.0 3.7%World 1810.4 2721.1 3468.3 2.6%

Chapter 8 - Gas 125

these factors are taken into account, it is estimated that non-OECD gasdemand will grow during the projection period at an annual averagerate of 3.5%, well above the 0.2% projected for the OECD.

Table 8.2: Total Final Gas Consumption (Mtoe)

Table 8.3: Stationary2 Sector Gas Demand (Mtoe)

2. The Stationary Sectors are defined in Part IV.

1995 2010 2020 1995 - 2020Annual

Growth Rate

OECD 634.9 704.7 661.2 0.2%North America 379.2 384.8 345.7 -0.4%Europe 225.5 280.5 274.2 0.8%Pacific 30.3 39.4 41.3 1.2%Non-OECD 383.7 644.3 899.1 3.5%Transition Economies 232.0 331.6 428.3 2.5%Africa 11.3 17.5 23.5 2.9%China 13.1 36.2 46.7 5.2%East Asia 19.2 45.1 71.4 5.4%South Asia 18.9 54.8 91.8 6.5%Latin America 49.8 94.3 133.8 4.0%Middle East 39.4 64.8 103.6 3.9%World 1018.6 1348.9 1560.3 1.7%

1995 2010 2020 1995 - 2020Annual

Growth Rate

OECD 612.8 673.6 623.3 0.1%North America 357.6 354.1 308.1 -0.6%Europe 225.1 280.1 273.9 0.8%Pacific 30.1 39.4 41.2 1.3%Non-OECD 369.2 621.1 866.2 3.5%Transition Economies 219.1 311.0 398.7 2.4%Africa 10.8 17.0 23.0 3.1%China 13.0 36.1 46.6 5.2%East Asia 19.2 45.0 71.4 5.4%South Asia 18.9 54.8 91.8 6.5%Latin America 48.8 92.4 131.2 4.0%Middle East 39.4 64.8 103.6 3.9%World 982.0 1294.7 1489.5 1.7%


Details of the stationary sectors projected gas demands are shownin Table 8.3.

Power GenerationGas demand is projected to grow especially quickly in power

generation3. The high efficiency of combined cycle gas turbines(CCGTs), and their low emissions of CO2 and SO2, make themparticularly attractive for generating electricity. Within the OECD,growth in the use of gas for power generation is projected to be rapid, atan annual average rate of 4.5%. OECD Europe’s growth in gas demandfor power generation is the most rapid of all OECD regions, at 7.3%per annum. In the other two OECD regions, growth is projected to bemore modest, at around 3%, because coal or nuclear power will oftenremain the preferred option for base load electricity generation.

Table 8.4: Power Generation Gas Demand (Mtoe)

Although gas demand growth in the non-OECD’s powergeneration sector is projected to be somewhat lower than in theOECD, 3.5% compared to 4.5% per annum, non-OECD demand inthis sector already exceeds that from the OECD. Gas demand in thenon-OECD is dominated by the Transition Economies, where gas hasoften been used in the past to free up other fossil fuels, particularly oil,

1995 2010 2020 1995 - 2020Annual

Growth Rate

OECD 227.4 525.2 678.1 4.5%North America 131.6 253.5 270.7 2.9%Europe 55.0 194.4 318.9 7.3%Pacific 40.8 77.3 88.5 3.1%Non-OECD 337.2 508.6 798.9 3.5%Transition Economies 228.0 267.1 350.8 1.7%Africa 15.3 33.6 52.9 5.1%China 0.7 12.4 23.6 14.9%East Asia 27.1 64.8 108.9 5.7%South Asia 11.8 26.4 54.1 6.3%Latin America 20.7 48.7 112.4 7.0%Middle East 33.5 55.6 96.2 4.3%World 564.6 1033.8 1477.0 3.9%

3. See Chapter 6 and Part III for more information on the increasing use of gas for powergeneration.

Chapter 8 - Gas 127

for export. If the Transition Economies are excluded from the non-OECD figures, then gas demand in the power generation sector isprojected to grow at an annual average rate of 5.8%

Table 8.5 summarises the demand and supply gas projections interms of million tonnes of oil equivalent (Mtoe).

Table 8.5: Summary Table for the BAU Gas Projection (Mtoe)

Units and RegionsThe following section presents the Outlook’s gas supply

projections. Whereas the Outlook’s demand projections are preparedin terms of million tonnes of oil equivalent (Mtoe), gas supply istraditionally measured in trillion cubic feet (tcf )4 and the BAU supplyprojections are presented in these units in Table 8.6.

Indigenous Production 1995 2010 2020


Net Imports 1995 2010 2020

OECD North America (including Mexico) -2 -2 -2OECD Europe 104 230 387OECD Pacific 42 42 64Transition Economies -74 -162 -281China 0 0 0Rest of World (excluding Mexico) -76 -114 -174World -8 -6 -6

Total Primary Gas Supply 1995 2010 2020


4. Throughout this Outlook the following conversion factor has been applied 1 Mtoe = 0.0429 tcf.


While Mexico is included under Latin America elsewhere in theOutlook, in the gas supply analysis Mexico is included in OECDNorth America. This alternative definition arises from Mexico’sextensive gas reserves, which could in the long run be exported to theUS. These exports would require large capital investments in pipelineinfrastructure, but could come into service before 2020 if the US wereunable to satisfy gas demand from Canadian and domestic reserves.Currently, the US is a net exporter of gas to Mexico, but this positioncould be reversed towards the end of the projection period if US gasreserves proved to be less abundant than assumed by somecommentators.

Table 8.6: Total Primary Energy Supply (tcf )

1 Mtoe = 0.0429 tcf

Gas SupplyThis section presents the BAU projections for gas supply,

including conventional and unconventional gas. For the world as awhole, our calculations indicate that cumulative consumption of gasto 2020 will be less than one half of the United States GeologicalSurvey (USGS) ultimate conventional gas reserves. In world terms,therefore, reserves are not expected to constrain gas production in theOutlook period. At present, the world gas market can be consideredas five separate markets:

1995 2010 2020 1995-2020Annual

Growth Rate

OECD 41 57 61 1.7%North America (excl. Mexico) 25 30 29 0.6%Europe 13 22 27 3.0%Pacific 3 5 6 2.4%Non-OECD 37 60 87 3.5%Transition Economies 21 28 36 2.1%Africa 2 3 4 3.9%China 1 2 3 6.5%East Asia 3 8 12 5.5%South Asia 1 4 7 6.4%Latin America (incl. Mexico) 4 8 13 4.9%Middle East 4 7 11 3.7%World 78 117 149 2.6%

Chapter 8 - Gas 129

• Europe, North Africa and the Transition Economies• North America and Mexico• Asia Pacific• Middle East• Latin AmericaThe markets are linked by LNG trade, a large part of which serves

Japan. In the future, major new pipelines and increased LNG tradeare expected to increase the linkages between markets. Attentiontherefore needs to be given to gas trade prospects.

For regions outside North America, the projections in thisOutlook have been prepared using the 1994 USGS5 estimates ofultimate6 conventional gas reserves. The 1994 USGS estimated thatglobal conventional ultimate gas reserves were around 11500 tcf, orapproximately 2000 billion barrels of oil. Details of this estimate canbe found in Table 8.7. The 1994 USGS’ ultimate gas reserves estimateis at the lower end of the range of ultimate oil reserves assumed in thisOutlook7. Perrondon et al provide similar estimates of ultimate gasreserves to that of the USGS and estimate a range of 9000-13000 tcfwith a mean of 10000 tcf8.

The USGS’ estimated ultimate conventional gas reserves areshown in Table 8.7. Cumulative world production to 1993 hadreached only 15.3% of the USGS estimate of ultimate reserves ofconventional gas. The figures for OECD North America aremisleading in this table, as gas production in this region includessubstantial amounts of unconventional gas (mainly coal bed methaneand tight reservoir gas). For this reason, gas supply projections forNorth America are considered separately below. Gas supply in OECDEurope has been the subject of an IEA study9 and is also treatedseparately.

Estimates of gas reserves are expected to grow over time becauseuncertainty is reduced and technology develops, new gas is discoveredand upward revisions are made to identified reserves. In many parts ofthe world, gas reserves are known to exist, but the lack of a suitable

5. World Petroleum Assessment and Analysis, Masters, C.D et al, Proceedings of the 14th WorldPetroleum Congress, 1994, Published by John Wiley and Sons.6. Ultimate reserves = Cumulative Production + Remaining Recoverable Reserves + Undiscovered.7. See Chapter 7 for details of the 2000 - 3000 billion barrels range of ultimate oil reserves.8. The World’s Non-Conventional Oil and Gas, Hydrocarbons of last recourse, A. Perrondon, J.H.Laherrère and C.J. Campbell, published by The Petroleum Economist Ltd in March 1998 (ISBN1 86186 062 5), see page 98 for further details.9. The IEA Natural Gas Security Study, IEA/OECD Paris, 1995.


infrastructure to get them to consumers means that they are notcurrently considered economic. These finds are referred to as“stranded” gas. It is likely that this gas will increasingly be exploited asexisting pipeline systems are extended, as markets are developed closerto stranded gas reserves or via Gas-to-Liquids technology (see Chapter 7). In addition, unconventional gas reserves may be exploitedas technology develops and gas prices rise to make it economic to do so.

Table 8.7: USGS Ultimate Conventional Gas Reserves (tcf )

Note : Ultimate Reserves = Cumulative Production + Remaining Recoverable Reserves + Undiscovered.1 Mtoe = 0.0429 tcf or 1 tcf = 23.31 Mtoe.* Production in OECD North America includes unconventional gas.

Simple models have been adopted for gas supply. For regions otherthan North America and OECD Europe, gas production is assumed tofollow a modified Hubbert Curve10 to ensure that a link exists betweencumulative gas production and estimated recoverable reserves of gas. Inorder to allow for further increases in gas reserve estimates, gas productionis allowed to increase until 60% (instead of the normal 50%) of theUSGS’ estimated ultimate conventional gas reserves for the region havebeen produced. Once that threshold has been reached, gas production isassumed to decline by 5% per annum. The difference between a region’sconsumption and post-peak production is met by imports of gas fromother regions. Gas imports are allocated to gas exporting countries on thebasis of judgement. They are especially uncertain.

10. Chapter 7 discusses the Hubbert Curve.

Region Ultimate Production Cumulative CumulativeReserves (1992) Production Production /

(end 1992) Ultimate Reserves

OECD North America 2151.9 23.3* 899.1* 41.8%*OECD Pacific 113.2 1.1 10.2 9.0%OECD Europe 655.7 7.6 159.8 24.4%Africa 746.6 3.0 31.1 4.2%Latin America 485.4 2.3 39.7 8.2%S and E Asia 596.0 5.1 51.8 8.7%Transition Economies 3886.6 27.5 493.5 12.7%Middle East 2585.6 3.7 49.8 1.9%China 227.0 0.6 15.2 6.7%World 11448.0 74.2 1750.2 15.3%

Chapter 8 - Gas 131

North AmericaAs noted in relation to Table 8.7, the cumulative production of gas

is already approaching 50% of the 1994 USGS estimate of ultimatereserves of conventional gas. Account needs to be taken therefore of boththe production of unconventional gas and the substantial increase inestimates of North American gas reserves since the 1994 USGS estimates.

The United StatesAccording to Perrondon et al11, unconventional gas currently

contributes up to 20% of total gas production in the US and accountsfor three out of every four gas wells drilled. Since 1990, Perrondon etal state that unconventional gas has accounted for almost all thegrowth in US gas production12.

Table 8.8 compares the 1994 USGS13 estimate of remainingconventional gas reserves for the United States at 1/1/93 of 632 tcfwith the resource assumptions underlying the USDOE/EIA AnnualEnergy Outlook 199814. The higher USDOE/EIA conventionalresources reflect the substantial increase in conventional inferredreserves as of 1/1/94 in a later 1995 USGS assessment.

Calculation of the ratio of cumulative gas production to ultimatereserve estimate indicates that some 65% of the latest reserve estimatewill be produced by 2020 in the Reference Case of the USDOE/EIA1998 Annual Energy Outlook, and gas production will still be risingat that point. If gas supply tightened, gas prices would rise. A modestrise in gas prices is included towards 2020 in the USDOE/EIAOutlook. The IEA Outlook takes the view that some increase in thegas price is likely to be necessary to match gas supply and demand, butthe price rise is assumed not to be sufficient to attract significant LNGimports into the United States.

The uncertainties on gas reserves and gas production in theUnited States over the period to 2020 are clearly substantial. The USDOE’s assumption, in Table 8.8, that new technology will add

11. op.cit.12. The World’s Non-Conventional Oil and Gas, Hydrocarbons of last recourse, A. Perrondon,J.H. Laherrère and C.J. Campbell, published by The Petroleum Economist Ltd in March 1998(ISBN 1 86186 062 5), see page 24 for further details.13. World Petroleum Assessment and Analysis, C.D. Masters, E.D. Attanasi and D.H. Root,Proceedings of the 14th World Petroleum Congress, 1994.14. Annual Energy Outlook 1998, Energy Information Administration, US Department of Energy,USDOE/EIA- 0383(98), December 1997.


some 30% to gas reserves by 2020 is uncertain, as gas reservoirs havemuch higher recovery factors than oil reservoirs, leaving less room fornew technology to increase recoverable reserve estimates. Less than30% of the USDOE’s (1998) existing conventional gas reserves areproven. Finally, the costs of much of the remaining unconventionalgas reserves are unknown.

Table 8.8: Estimates of Gas Reserves in the United States

CanadaA similar position exists in Canada with respect to the uncertainty

surrounding the quantity of gas reserves, as Table 8.9 demonstrates.Table 8.9 can be compared with the USGS’ (1994) estimates ofCanadian conventional ultimate gas reserves of 485 tcf, of which 82tcf had been produced as of 1/1/1993.

According to this table, recoverable reserves of Canadianconventional gas could be in the range from 93 - 292 tcf. In the caseof unconventional gas, recoverable reserves are clearly substantial butare even more difficult to estimate.

The above estimates suggest that although considerable reservesof unconventional gas exist in North America, there is muchuncertainty about their size, cost and future production levels.

It is possible to develop a wide variety of gas supply projectionsfor the region. One scenario was examined by the IEA in early 1998,for the G8 Ministerial Meeting. It used the USGS’ estimates of

USGS (Masters 1994) tcfRemaining conventional reserves at 1/1/93 632

US EIA/DOE (1998) remaining reserves to 1/1/97Conventional proved, inferred and undiscovered 731Unconventional 247Upgrade from 1997 to 2020 technology 316Current remaining reserves 1294

Cumulative production to 1/1/97 871Cumulative production 1997-2020 567Cumulative production to 2020 1438

Cumulative production to 2020 1438Ultimate reserves (871 + 1294)

= 66%

Chapter 8 - Gas 133

OECD North America’s conventional gas reserves in conjunction withan assumption that regional gas production would peak when 65% ofthe region’s reserves had been produced15. That scenario led to a largeimport requirement of LNG. We have rejected this scenario on thegrounds that the rise in gas price necessary to attract LNG importswould probably reduce demand and stimulate additional indigenousgas supply sufficiently to render the imports unnecessary. In thisOutlook, an alternative scenario has been developed in which it isassumed that a combination of a gas price increase, improvements intechnology and greater use of unconventional gas allows OECDNorth America to meet the projected increase in gas demand duringthe period 1995 - 2020 from domestic sources. For the purposes of theBAU projection, it has been assumed that between 2005 and 2015 theprice of gas increases linearly from $1.7 to $3.5 (US dollars) perthousand cubic feet. Increasing the gas price in this manner meansthat although limited imports of LNG may occur, they will most likelyreflect local mismatches in supply and demand.

Table 8.9: Estimates of Canadian Gas Reserves (tcf )

Sources: Canada’s Energy Outlook 1996 - 2020, Natural Resources Canada.Natural Gas Potential in Canada, A Report by the Canadian Gas Potential Committee, 1997.

OECD EuropeOECD Europe’s gas production is assumed to grow by 2.2% per

annum16 until cumulative production reaches 60% of the USGS’

15. World Energy Prospects to 2020, paper prepared by the IEA for the G8 Energy Ministers’ Meeting held in Moscow on the 31st March 1998.

16. This assumption has been taken from Table 3.18, page 75 of The IEA Natural Gas SecurityStudy, IEA/OECD Paris 1995.

Canada’s Energy Canadian Gas PotentialOutlook 1996 - 2020 Committee 1997

Conventional Gas Proven Potential Recoverable Initially In PlaceConventional Areas 68 255 185 448Frontier Areas 25 270 107 121

Total 93 525 292 569

Unconventional GasCoal Sources 20 250 - 2600 135 - 261 n.a.Tight Gas / Shale Gas n.a. n.a. n.a. 175 - 3500


Table 8.10: BAU Gas Supply and Demand Projections (tcf )

1995 2010 2020 AnnualGrowth

RateIndigenous ProductionOECD 35.2 47.7 45.9 0.7%OECD North America (including Mexico) 25.4 32.5 32.8 0.7%OECD Pacific 1.3 3.3 2.9 2.1%OECD Europe 8.5 11.8 10.2 0.5%Non-OECD 42.8 69.3 103.2 3.6%Africa 3.2 5.6 8.3 3.4%Latin America (excluding Mexico) 2.9 5.7 9.4 4.4%South and East Asia 6.2 11.7 17.9 3.8%Transition Economies 25.1 34.7 47.9 3.0%Middle East 4.7 9.2 16.1 4.5%China 0.7 2.4 3.5 5.0%World 78.0 117.0 149.0 2.5%Net ImportsOECD 6.2 11.6 19.3 3.9%OECD North America (including Mexico) -0.1 -0.1 -0.1 0.0%OECD Pacific 1.8 1.8 2.8 1.7%OECD Europe 4.5 9.9 16.6 4.3%Non-OECD -6.4 -11.8 -19.5 3.8%Africa -1.5 -2.6 -4.0 3.2%Latin America (excluding Mexico) 0.0 0.0 0.0 0.0%South and East Asia -1.5 -0.1 1.4 n.a.Transition Economies -3.2 -6.9 -12.0 4.5%Middle East -0.2 -2.1 -4.9 9.1%China 0.0 0.0 0.0 n.a.World -0.2 -0.2 -0.2 0.0%Total Primary Energy SupplyOECD 41.9 59.3 65.2 1.4%OECD North America (including Mexico) 25.8 32.5 32.7 0.7%OECD Pacific 3.1 5.1 5.7 1.9%OECD Europe 12.9 21.7 26.8 2.4%Non-OECD 35.8 57.5 83.6 3.5%Africa 1.7 3.0 4.4 3.6%Latin America (excluding Mexico) 2.9 5.7 9.5 4.4%South and East Asia 4.7 11.5 19.3 5.0%Transition Economies 21.4 27.7 35.8 2.6%Middle East 4.5 7.0 11.2 3.4%China 0.7 2.4 3.5 5.0%World 77.6 116.7 148.8 2.5%1 Mtoe = 0.0429 tcf or 1 tcf = 23.31 Mtoe.

Chapter 8 - Gas 135

estimated ultimate reserves, at which point production is assumed todecline by 5% per annum thereafter.

Table 8.10 presents the gas supply projections for the BAUprojection.

Gas TradeThe dependence of OECD Europe and OECD Pacific on non-

OECD supplies of gas steadily increases throughout the projectionperiod. Gas imports into OECD Europe triple during the projectionperiod, mainly by pipeline from the Transition Economies and NorthAfrica. Imports of gas from new sources, such as the Middle East andcountries surrounding the Caspian Sea, are also possible by the end ofthe projection period. It is likely that these new gas imports would haveto come by pipeline via Turkey (large imports of LNG would almostcertainly be too expensive). The main problem is one of transportingthe gas to OECD Europe rather than gas reserve limitations.

As these additional sources of imports would have to compete onprice with gas from Russia and Algeria in order to win market share,there may be some downward pressure on the import price of gas.Current cost estimates suggest, however, that gas from the Caspian isnot competitive with either Algerian or Russian pipeline gas17. Forexample, the cost of supplying Turkmen gas to Western Europe rangesfrom $127 - $152 per thousand cubic metres compared to Algerianpipeline gas at $64 per thousand cubic metres and Russian pipeline gasat $113 - $131 per thousand cubic metres. Imports of Caspian gasinto OECD Europe may therefore have to wait until cheaperadditional supplies of gas from Algeria and Russia have beenexhausted, or until the higher costs of new sources of gas can bejustified on the grounds of diversification of supply. It should also notbe forgotten that Norway is a major supplier of gas to other OECDEurope countries and that increases in the gas price would almostcertainly result in additional volumes of Norwegian gas beingdelivered.

Another possible source of imports into OECD Europe is liquidnatural gas. As LNG trade grows, an LNG spot market could developover time as a result of a number of factors in much the same way asfor oil during the last 30 years.

17. Caspian Oil and Gas, The Supply Potential of Central Asia and Transcaucasia, IEA/OECD Paris1998, page 107.


Figure 8.1: OECD Europe’s Gas Balance

OECD Pacific’s net imports of gas are projected to rise by 56%during the projection period. The import position of this region iscomplicated by the fact that whereas Japan is a net importer of gas,Australia exports LNG and plans to increase its exports. Thisdifference in Australia and Japan’s net import positions explains whythe region’s indigenous gas production is projected to rise at an annualaverage rate of 2.1%, while, at the same time, net imports grow at 1.7%.

Total gas demand outside the OECD is projected to grow at anannual average rate of 3.5% (2.1% for the Transition Economies and4.9% in the developing countries) during the projection period;however, gas production will grow slightly more rapidly, at 3.6% perannum, in order to satisfy the OECD’s need for gas imports. Withinthe non-OECD, South and East Asia will switch from being a netexporter of gas to become a net importer. Net exports of gas from theTransition Economies, Africa and the Middle East are all projected torise during the projection period and this will result in the non-OECD’s exports of gas more than tripling between 1995 and 2020.

Despite projected rapid growth in non-OECD gas production,none of the individual non-OECD regions is expected to have reachedthe 60% point of ultimate gas reserves by 2020, the point at which gasproduction is assumed to go into decline in these projections. Thus,gas production in all non-OECD regions is projected still to be

Net Imports

Indigenous Production

mill

ion

tonn

es o

il eq

uiva

lent

800

600

400

200

01995 2000 2005 2010 2015 2020

Chapter 8 - Gas 137

increasing in 2020. The position of the non-OECD in 2020 contrastssharply with that of the OECD, in which 70% to 80% of the USGS’estimated ultimate conventional gas reserves will have been produced.

Table 8.11: Cumulative Gas Production as a Percentageof the USGS’ Estimated Conventional Gas Reserves

Note : Only conventional gas reserves are considered in the above table.

Figure 8.2: World Gas Production

Worldwide gas production is not expected to peak until well after2020. Over the whole of the projection period, gas supply is projected

Non - OECD

OECD

trilli

on c

ubic

feet

150

125

100

75

50

25

01995 2000 2005 2010 2015 2020

1995 2010 2020

OECD North America n.a. n.a. n.a.OECD Pacific 12.3% 43.4% 72.9%OECD Europe 28.1% 51.5% 69.8%Africa 5.4% 14.3% 23.5%Latin America excluding Mexico 9.8% 22.8% 38.6%South and East Asia 7.7% 29.6% 54.7%Transition Economies 14.7% 25.3% 35.7%Middle East 2.4% 6.4% 11.2%China 7.6% 17.9% 30.9%World 17.1% 29.7% 41.3%


to grow by 91%. The assumption is made that OECD NorthAmerica’s gas supply and demand will be in balance throughout theprojection period. Production in OECD Europe and in OECDPacific will be declining as 2020 approaches.

Comparisons with Other Organisations’ Gas ProjectionsThe International Energy Outlook 199818 published by the

USDOE/EIA provides regional gas consumption projections againstwhich the BAU’s TPES projections described earlier can be compared.The USDOE publication does not provide sufficient information fora comparison to be made of gas production. Table 8.12 compares thetwo demand projections.

Table 8.12: USDOE versus IEA Gas Demand ProjectionsAnnual Growth Rates 1995 - 2020

One of the most notable features of Table 8.12 is the lower growthrate in gas demand in the IEA projection than in the USDOE projectionfor OECD North America. This difference arises from the link in theIEA’s gas supply model between gas production and gas reserves. Becauseof uncertainties on future gas reserves in OECD North America, theIEA’s BAU projection assumes that between 2005 and 2015 the price ofgas increases linearly from $1.7 to $3.5 per thousand cubic feet. Whereasin the IEA projection, gas demand in OECD North America

18. International Energy Outlook 1998, USDOE/EIA-0484(98), Energy InformationAdministration, US Department of Energy, April 1998.

USDOE Reference Case IEA BAU Projection

OECD 2.5% 1.7%OECD North America 1.6% 0.6%OECD Europe 3.8% 3.0%OECD Pacific 1.6% 2.4%Non-OECD 3.9% 3.5%Transition Economies 2.4% 2.1%South and East Asia 7.3% 5.8%China 7.5% 6.5%Middle East 2.6% 3.7%Africa 2.8% 3.9%Latin America 6.1% 4.9%World 3.3% 2.6%

Chapter 8 - Gas 139

actually declines slightly between 2010 and 2020 because of the gas priceincrease, in the USDOE projection, gas demand continues to grow.

A second projection against which the Outlook’s gas projectionscan be compared is that of the European Union. The EU’s publicationEuropean Energy to 2020: A Scenario Approach19 provides projections on both gas production and consumption. For the purposes of thiscomparison, the EU’s Conventional Wisdom (CW)scenario has beenused as it represents the closest match, in terms of assumptions, to theIEA’s BAU projection. Table 8.13 compares the IEA, USDOE and EUgas consumption projections.

Table 8.13: EU versus IEA Gas Demand ProjectionsAnnual Growth Rates 1995 - 2020

Note : The EU projections are two years older than either the IEA or USDOE projections and,so, at the time they were being prepared, 1995 energy data were unavailable. The EU’s publicationreference year is therefore 1990 and not 1995. However, the omission of 1995 alone should notgreatly alter its projections.* The EU projections do not separate China from the rest of Asia.

Probably the most significant difference between the EU and IEAprojections concerns the Transition Economies. The EU growthprojection is 0.6 percentage points below that of the BAU projection(2.1% versus 1.5%). Since the Transition Economies accounted for

19. European Energy to 2020: A Scenario Approach, Energy in Europe, DG XVII, EuropeanCommission, Special Issue - Spring 1996.

EU (1990 - 2020) IEAConventional Wisdom BAU Projection

OECD 2.3% 1.7%OECD North America n.a. 0.6%OECD Europe n.a. 3.0%OECD Pacific n.a. 2.4%Non-OECD 2.9% 3.5%Transition Economies 1.5% 2.1%South and East Asia * 6.4% 5.8%China * 6.4% 6.5%Middle East 3.7% 3.7%Africa 5.0% 3.9%Latin America 5.6% 4.9%World 2.7% 2.6%


38% of global gas consumption in 1990, small variations in theregion’s growth rate can have large impacts on the projected non-OECD gas consumption. Thus, the EU’s lower projected growth ratefor the Transition Economies results in their projection for the non-OECD’s being lower than that projected by the BAU. At the worldlevel, however, there is little to choose between the two projections,with the EU projecting faster growth in the OECD’s gas consumptionthan the IEA. This difference almost exactly offsets the difference inprojections for the Transition Economies, with the result that at aglobal level there is little difference between the two organisations’ gasprojections.

Interestingly, the EU’s rapid growth rate in OECD gasconsumption suggests that either it does not have an explicit linkbetween gas reserves and production in its gas supply model (as withthe USDOE), or it is projecting large gas imports into OECD NorthAmerica. Table 8.14 compares the BAU and EU gas balances for theOECD in 2020.

Table 8.14: OECD Gas Balances in 2020 IEA BAU versus EU CW (Mtoe)

It is evident from the above table that when allowance is made forthe difference in TPES projections (93 Mtoe in 2020), gas productionin the BAU projection is approximately 260 Mtoe higher than in theEU projection. Similarly in the EU projection, adjusted net importsare around 260 Mtoe higher than in the BAU projection. The EUprojections do not separate out total OECD into its three regions, butthey provide separate gas production projections for the USA and EU.An examination of these projections shows the USA’s gas productionfalling from 419 Mtoe in 1990 to 364 Mtoe in 2020. Similarly, theEU’s gas production starts at 133 Mtoe in 1990, and then rises to 174Mtoe in 2000 before declining to 131 Mtoe in 2020. Since the EU isprojecting total OECD gas production to increase from 714 Mtoe in1990 to 811 Mtoe in 2020, it expects gas production in countries such

IEA BAU EU CW Difference

Production 1070 811 259Net Imports 449 802 -353TPES 1519 1612 -93

Chapter 8 - Gas 141

as Canada, Mexico, Norway20 and Australia to offset the decline in gasproduction from the EU and USA.

The principal difference between the Outlook’s BAU projectionand the EU’s Conventional Wisdom projection lies in the growth ofgas production and net imports. In the BAU projection, it has beennoted that imports of LNG into OECD North America would requirea substantial gas price increase and that, as the price increased,additional unconventional and possibly also conventional gasproduction would be forthcoming. Also, since the BAU projectionassumes that OECD North America’s gas price more than doublesbetween 2005 and 2015, the projected increase in gas demand ismoderated by this price increase. In the EU’s projection, there seemsto be a large increase in OECD imports of gas without any mention ofthe gas price increasing in order to encourage these imports. Even ifthe increase in net imports were restricted to OECD Europe, therewould still be some upward movement in the price of gas imports and,therefore, in the delivered gas price.

The important point to note from the comparisons between theIEA, USDOE and EU’s gas projections for the OECD is thateventually rising gas demand will necessitate some increase in gasprices. This price increase will occur in North America in order toensure that either indigenous gas production or net imports risesufficiently to meet gas demand. The link that exists between gasreserves, production and net imports in the IEA’s gas supply model istherefore important, as it ensures that gas demand is not allowed toincrease without questions being answered about the sources andabout the prices at which this additional demand can be supplied.

The uncertainties in these projections are very substantial and thedata available today for resolving the uncertainties are limited. This iswhy a comparison of projections can better identify the uncertaintiesand throw more light upon them.

20. Recall that Norway is a Member of OECD but voted not to become a Member of the EU.

CHAPTER 9COAL

Box 9.1: Coal Supply

Coal is used mainly in power generation, in industry and in theresidential sector. Demand in the non-power generation sectors hasbeen static in the OECD region for a number of years but isgrowing elsewhere. Consumption for power generation is growingworldwide. Two major factors will affect projections of coaldemand. The first will be the outcome of competition betweencoal and gas in power generation. The second will be the choice ofpolicies by governments to meet the greenhouse gas commitmentsentered into at Kyoto in 1997.

IntroductionThis chapter considers the prospects for coal during the

projection period 1995 to 2020. Unlike conventional oil, sufficientreserves of coal exist to meet world demand for the foreseeable future.Coal reserves are generally much more evenly distributed throughoutthe world than oil or gas reserves and strong competitive pressuresexist to minimise production costs. Security of supply is not an issueas lower coal production from one supplier can relatively easily besubstituted by additional production from another.

Because of the wide diversity of existing and potential coalsuppliers, a separate coal supply model has not been developed for thisOutlook. Instead, the approach taken is to assume that all theprojected increase in coal demand can be met from known reservesand that competition between suppliers will determine regional sharesin meeting global coal demand. Information on the prospects for eachregion’s coal supply are presented in the relevant regional chapter.

Previous versions of the World Energy Outlook aggregated coaland biomass

1into a category called solid fuels. This Outlook makes

use of recent IEA analysis to separate biomass and coal demandprojections for the first time, in non-OECD regions.

1. Also known as Combustible Renewables and Waste (CRW).

Chapter 9 - Coal 143


Coal Demand

Total Primary Coal DemandGlobal demand for coal is projected to grow at an annual average

rate of 2.2%. Overall, OECD demand is projected to grow at less thanhalf the rate of non-OECD demand. Within the OECD there aremarked differences. North America’s

2coal demand is projected to

grow at close to the global rate. In OECD Europe, demand isprojected to decline by 0.6% per annum. Similarly, OECD Pacific’sdemand for coal is projected to grow much more slowly than that ofOECD North America, at an annual average rate of just 0.5%. Thissubstantial increase in OECD North America’s coal demand arisesfrom an assumed rise in the gas price, producing lower gas demandand higher coal demand than would otherwise be the case. The reasonfor the high gas price in North America is discussed in Chapter 8.

Table 9.1: Total Primary Coal Demand (Mtoe)

Despite recent economic difficulties in Asia, the long-termoutlook for the region’s coal demand remains strong. Asian demand

2. Unless otherwise stated, OECD North America excludes Mexico, which is instead includedunder Latin America.

1995 2010 2020 1995 - 2020Annual

Growth Rate

OECD 904.4 1096.5 1219.0 1.2%North America 500.8 649.3 835.2 2.1%Europe 282.4 314.0 245.4 -0.6%Pacific 121.3 133.2 138.3 0.5%Non-OECD 1300.5 2013.4 2556.1 2.7%Transition Economies 300.2 357.0 359.6 0.7%Africa 81.6 111.7 136.9 2.1%China 663.7 1086.7 1415.9 3.1%East Asia 84.5 145.5 218.8 3.9%South Asia 139.8 255.6 347.7 3.7%Latin America 25.2 44.2 59.0 3.5%Middle East 5.4 12.7 18.2 5.0%World 2204.9 3109.9 3775.1 2.2%


outside China is projected to grow at an annual rate of around 3.8%and in China at 3.1%. The Middles East’s demand for coal isprojected to grow at 5% per annum. Around two-thirds of theadditional Middle East’s coal demand is for power generation,principally in those countries without large oil and gas reserves, suchas Israel. Most of the remaining increase is likely to occur in thosesectors, such as iron and steel making, where coal has few substitutes.Coal demand in the Transition Economies is projected to grow onlyslowly, reflecting the large potential for energy savings that still existsin these countries and the increasing use of oil and gas. Given theuncertainties surrounding the rate of economic growth andimprovements in energy efficiency, it is difficult to say how rapidly theTransition Economies’ coal demand will grow.

Total Final Consumption

Table 9.2: Total Final Consumption (Mtoe)

Within the OECD, virtually all of the region’s total finalconsumption of coal is consumed in the stationary sector and isprojected to decline slightly throughout the projection period. InOECD Europe, a return to average winter temperatures, from thewarm winters experienced for most of the 1990s, is expected to result

1995 2010 2020 1995 - 2020Annual

Growth Rate

OECD 155.7 145.6 150.2 -0.1%North America 38.8 38.8 43.5 0.5%Europe 72.7 66.4 67.6 -0.3%Pacific 44.1 40.4 39.1 -0.5%Non-OECD 660.2 906.0 1067.8 1.9%Transition Economies 109.5 119.5 121.2 0.4%Africa 20.7 25.5 29.3 1.4%China 415.9 617.3 755.4 2.4%East Asia 46.7 53.5 56.7 0.8%South Asia 50.4 69.9 81.5 1.9%Latin America 15.8 18.6 21.4 1.2%Middle East 1.2 1.6 2.3 2.7%World 815.9 1051.6 1218.0 1.6%


in a small short-term increase in coal demand. In the longer term,however, the switch to other fuels, principally gas, will more thanoffset this short-term effect.

Non-OECD final consumption of coal is projected to increase byover 400 Mtoe between 1995 and 2020. Growth is expected to bedominated by China, which already accounts for 63% of total non-OECD coal demand. By 2020, China’s share of non-OECD coaldemand is projected to increase to 71%. China’s share of global finalcoal consumption leaps from 51% to 62% between 1995 and 2020.By 2020, China’s final consumption of coal is expected to be over fivetimes greater than that of the entire OECD.

Power Generation3

With the exception of OECD Europe, coal demand for powergeneration is projected to increase in every region. But, tighteremission controls and the switch to gas will reduce the extent to whichcoal consumption can grow in many regions. In the case of OECDEurope, these factors combine with the cost competitiveness of CCGTplants relative to coal plants to lower coal demand by 16% in 2020compared with 1995. In North America, coal demand is projected togrow at an annual average rate of 2.2%. Growth in OECD Pacific isprojected to be more modest, at 1.2% per annum.

Total non-OECD demand for coal in this sector grows at anannual average rate of 3.6%, more than twice the OECD’s growthrate. Growth in non-OECD demand will, however, be dampened bylow demand growth in the Transition Economies. This low rate ofgrowth results in China increasing its share of non-OECD coaldemand from 41% to 46% during the projection period. Elsewhere inAsia, coal demand for power generation is also expected to growrapidly, at an annual average rate of 4.9%. In Latin America and theMiddle East, demand will grow even more rapidly than in Asia, butthe current low level of coal demand in these regions means that theadditional volumes demanded by 2020 will be relatively modest.

In sum, the power sector’s demand for coal will increasingly bedominated by Asia. Asia’s share of world demand is projected to increasefrom 28% in 1995 to 43% by 2020. OECD North America will remain thelargest consuming region, but China’s rapid growth during the projectionperiod will reduce the size of North America’s lead considerably by 2020.

3. The prospects for coal in power generation are discussed in each of the regional chapters inPart III and in Chapter 6. This section therefore highlights the main global trends.


Table 9.3: Power Generation (Mtoe)

Coal Supply

ReservesWhereas oil reserves are concentrated in the Middle East and gas

reserves in the Middle East and Former Soviet Union (FSU), coal canbe found in large quantities throughout the world. Coal reserves at theend of 1996 are shown in the following table, along with production.

The global ratio of coal reserves to production was 224 years atthe end of 1996. For the OECD, the ratio was even larger at 237years. Coal reserves are not expected to act as a constraint on coalsupply until well into the next century. In order to obtain a view onwhich countries are likely to be major coal suppliers during theprojection period, Table 9.5 lists the top-10 countries in terms of coalreserves and their shares of world coal reserves.

1995 2010 2020 1995 - 2020Annual

Growth Rate

OECD 719.6 921.7 1039.5 1.5%North America 456.1 604.3 784.8 2.2%Europe 197.9 235.9 166.9 -0.7%Pacific 65.6 81.5 87.8 1.2%Non-OECD 586.9 1038.4 1413.7 3.6%Transition Economies 163.9 210.5 212.3 1.0%Africa 43.8 65.1 83.3 2.6%China 240.7 458.7 647.5 4.0%East Asia 33.5 87.1 157.0 6.4%South Asia 92.6 181.8 261.7 4.2%Latin America 8.3 24.3 36.1 6.1%Middle East 4.2 11.0 15.8 5.5%World 1306.5 1960.1 2453.3 2.6%


Table 9.4: Coal Reserves and Production

Source: British Petroleum Statistical Review of World Energy, 1997.* Including Mexico.** Excluding Poland and Hungary.*** Excluding the Republic of Korea.

Table 9.5: Percentage of World Coal Reserves by Country (1996)

Source: British Petroleum Statistical Review of World Energy, 1997.

A strong relationship exists between this ranking and the top 10countries in terms of production shown in Table 9.6.

FSU 23.4USA 23.3China 11.1Australia 8.8India 6.8Germany 6.5South Africa 5.4Poland 4.1Indonesia 3.1Canada 0.8

Total 92.5

Reserves - End 1996 Percentage Production - 1996 Percentage(Billion Tonnes) of Total (Mtoe) of Total

OECD 430 41.6% 920.8 40.7%OECD North America* 250 24.3% 611.7 27.0%OECD Europe** 87 8.5% 173.2 7.6%OECD Pacific*** 92 8.9% 135.9 6.0%Non-OECD 602 58.4% 1343.3 59.3%Transition Economies 310 30.1% 310.8 13.7%Africa 617 6.0% 114.5 5.1%China 115 11.1% 680.6 30.1%Other Asia 105 10.2% 209.0 9.2%Latin America 10 1.0% 27.1 1.2%Middle East 0.2 0.0% 1.3 0.1%World 1032 100% 2264.1 100%


Table 9.6: Percentage of World Coal Production by Country (1996)

Source: British Petroleum Statistical Review of World Energy, 1997.

The level and pattern of regional coal production during theprojection period will be determined by competition within eachcountry between indigenous production and coal imports. Currentlythe proportion of coal traded internationally is small in proportion toworld coal production. In the case of hard coal, the proportion of coaltraded internationally is about 13%. The proportion is higher forcoking coal than for steam coal. Despite the low percentage ofinternationally-traded coal, a number of countries are likely to increasetheir level of coal exports. The prospects for each region’s coalproduction are briefly outlined below, with special emphasis on theexpanding international coal market

4.

AsiaChina and South Asia are both projected to increase their

demand for coal by more than 3% per annum during the projectionperiod. Coal demand in South Asia will continue to be dominated byIndia. China and India will therefore exert a large influence on thelevel of Asian coal production and international coal trade. Chinacould retain its position as a significant exporter of coal throughoutthe projection period. In 1996, China was responsible for 8.3% oftotal world steam coal exports. China could also import coal into itsSouthern regions.

4. Further information on the evolution of the international coal market can be found inInternational Coal Trade: The Evolution of a Global Market, IEA/OECD 1997.

China 30.1USA 25.0FSU 8.5India 6.2Australia 5.7South Africa 4.8Poland 3.8Germany 3.1Canada 1.8UK 1.4

Total 90.4


In India, the future level of coal production will primarily dependon the availability of finance to expand production capacity, washingplants and infrastructure. India could, in future, import coal fromIndonesia, South Africa and New Zealand, in addition to currentimports from Australia. Currently, however the protection enjoyed bydomestic coal, port capacity and facilities restrain the level of imports.The distribution of these imports is also limited to a small coastal areabecause of rail capacity and costs. India has ample coal reserves fromwhich to supply its growing domestic market. The problem is not oneof reserves, but the rate at which production capacity can be expandedand its location relative to potential consumers. Currently, India’s coalproduction and transportation capacity is not expanding rapidlyenough to satisfy domestic coal demand.

North AmericaThe United States is a major player in the international steam coal

market. Considerable excess production and export capacity exists inthe US, and this effectively places a limit on the extent to whichinternationally traded coal prices can rise. The relatively high pricelevel at which US producers enter the export market provides someshelter for the development of new capacity in other less expensiveregions, such as Latin America, Indonesia and China.

Canada’s exports are primarily coking coal, although some steamcoal is also exported. Canadian exports face the challenge that the minesare situated more than 1000 kilometres from the nearest internationaldeep-water port on the west coast and so transportation costs are amajor element in the total delivered cost of Canadian coal exports.

Latin AmericaThere is a large amount of pre-production capacity at an

advanced stage of planning in this region. Much of Latin America’snew capacity during the projection period is likely to be relatively lowcost. The main export markets for Latin American coal are the US andEurope. Since European coal demand is projected to decline duringthe projection period, any additional Latin American coal productionexported to Europe will have to first displace existing coal suppliers.

Colombia and Venezuela currently dominate Latin America’s coalproduction. Colombia is already an established steam-coal exporter,with plans for significant expansion. With vast reserves of low-cost,low-sulphur, low-ash coal, Colombia has the potential to increase its


coal exports significantly during the projection period. Colombia iswithin good shipping distances of the US and European markets,although currently most coal exports go to Europe. In the past, lack ofinfrastructure has limited Colombia’s coal production, but if thedeepwater port at Puerto Bolivar were expanded, and improvementsmade to railway and handling facilities, Colombia’s export capacitycould double. In 1996, Colombia exported 24.9 million metric tons(Mt) of its total coal production of 30.1 Mt.

Venezuela is currently a small exporter but has considerable scopefor expansion. It is similarly placed to Colombia with good qualitycoal and access to European and US markets. Currently, Venezuelanexports of coal are around 4 Mt per annum and will remain limited tothis level without construction of a dedicated rail link and improvedport facilities. One proposal for a new rail link and coal terminalwould allow exports to be increased to 10 Mt per annum. The limitingfactor on Venezuela’s future coal exports is not therefore lack ofreserves but infrastructure.

Transition EconomiesThe future of coal production in Eastern Europe depends heavily

on the successful implementation of current restructuring plans,particularly in Poland, Ukraine and Russia. The Outlook for theserestructuring plans is not favourable, and production destined forexport is likely, at best, to stabilise at current levels for the foreseeablefuture.

PacificAustralia and Indonesia are the major producing countries in this

region. In Australia, there is a large quantity of pre-productioncapacity at an advanced stage of planning, while in Indonesiaconsiderable flexibility exists. In the immediate future, Australiarepresents a likely source of additional supplies of coal to the worldmarket. Australia is well situated to be the natural supplier of coal tothe growing Asian markets. How successful the country will be inincreasing its exports to Asia will depend on its ability to compete withIndonesia and China. Australia will also face competition from SouthAfrican exports of coal into the Asian markets. A key factordetermining Australia’s future level of coal production will be itsability to contain production and transportation costs. Improvingindustrial relations will be important. The Australian Bureau of


Agricultural and Resource Economics has estimated that an additional47 Mt of capacity could be developed quickly, if returns are judgedsufficient.

Between 1980 and 1996, Indonesian coal production increasedfrom 0.3 to 45 Mt. This exceptional growth has been driven by largereserves of good quality coal, proximity to markets, high labourproductivity and low labour costs. Government policies haveencouraged foreign investment in the coal industry. Historically,Indonesian coal production has been dominated by exports (over 75%of production was exported in 1995), but during the projection periodthe domestic market is expected to become increasingly important. Inthe past, some doubts have been expressed about physical limits onexport-quality Indonesian coal resources, but recent IEA researchsuggests that they may be less serious than previously thought.Exports are thought likely to continue to expand.

Southern AfricaSouth Africa is well situated to meet the growing demand for coal

imports into both Europe and Asia. Since the Europe-Atlantic marketfor coal has a large number of competing suppliers and the Asia-Pacificmarket a much narrower range of suppliers, South Africa can chooseto supply the market offering the highest price. South Africanarbitrage means that the world coal market tends to act as a singlemarket rather than several regional ones.

Despite South Africa’s ability to meet the growing global demandfor coal, the outlook for coal production in the country is highlyuncertain. South Africa faces two main problems: location ofadditional export coal production capacity and port capacity. The coalexport fields that are currently operating are approaching the ends oftheir economic lives and new production will have to come from coalreserves that are less well located for either domestic or export use.Traditionally, production of export-quality coal has resulted in largequantities of discards, which have been used domestically for powergeneration. The competitiveness of South African exports depends, inpart, on the use of discards and high-ash coal in the domestic market.Potential production areas in the northern part of the country do nothave a domestic market, and this lack is likely to act as a constraint oncoal production, even if the infrastructure problems can be solved.

Most exports of South African coal use the Richards Bay CoalTerminal. This port was already operating at close to full capacity in


1995, and although an expansion in capacity is planned for 1999,further port capacity will be necessary if exports are to continue toincrease. High rail-freight costs mean that the port of Maputo inMozambique is not currently a serious competitor to Richards Bay,but this may change during the projection period. For the foreseeablefuture, Richard Bay offers the only realistic outlet for any significantexpansion in South African coal exports

5. South Africa’s coal export

industry is currently a mid- to high-cost supplier when compared toother countries. Productivity rates are lower than in Australia andIndonesia. This suggests that even if the infrastructure problems aresolved, South African production costs may need to fall, or the Randto depreciate, for coal exports to be sufficiently competitive to winnew markets in Asia and Europe.

Western Europe6

The general outlook for coal production in Western Europe is notbright. Increasing pressure to reduce subsidies to the domestic coalindustry means that the region’s production looks certain to continueits decline. In Germany and Spain, political pressures appear likely todelay the full removal of subsidies, and to maintain some supportedproduction on social and regional grounds. Falling indigenousproduction will inevitably provide scope for a slight growth in importsof cheap coal into Western Europe, but competition from low-costgas, particularly in power generation, is expected to limit the increasein coal imports into Western Europe.

Supply OverviewOne common feature running through the above analysis is

uncertainty, principally the potential impact of climate change policieson coal demand. As argued in Chapter 4, it would be necessary to reducecoal demand from the levels projected in the BAU projection if thecommitments entered into at Kyoto in December 1997 are to be met.

Given these uncertainties, we have not made long-termprojections of regional coal production. The approach taken in thisOutlook has been to project regional demand for coal, and to assumethat the resulting global demand can be adequately sourced from thelarge number of potential suppliers. Figure 9.1 shows the BAU’sprojected increase in global coal supply.

5. Energy Policies of South Africa, IEA/OECD, 1996.6. The coal supply outlook for Western Europe is considered in more detail in the OECD Europe chapter.


Figure 9.1: World Coal Supply and Demand (Mtoe)

In practice, coal demand for the period to 2000 could be lowerthan shown in Figure 9.1 because of the lack of orders for coal-firedplants in North America since the early 1980s.

Comparison with Other ProjectionsTable 9.7 compares our projected regional coal demand and

global supply with projections prepared by the United StatesDepartment of Energy

7(USDOE) and European Union

8(EU). It

should be noted that the EU projections cover all solids and thereforeinclude combustible renewables and waste in addition to coal. A strictcomparison with the IEA projection is therefore not possible.

Two features stand out in comparing the USDOE and IEAprojections. First, both projections show global coal demand andsupply growing at an annual average rate of around 2%. Second, in themajority of regions, the USDOE is more pessimistic about futuredemand growth than the IEA. The factor resulting in similar demand

1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent

4000

3500

3000

2500

2000

1500

1000

500

0

7. See Table A5, page 138, of the USDOE/EIA International Energy Outlook 1998: WithProjections Through 2020, April 1998.8. Energy in Europe: European Energy to 2020 A Scenario Approach, European Commission,DGXVII, Special Issue - Spring 1996.


growth rates is the USDOE’s high growth rate for Chinese coaldemand. Since China is already the world’s largest consumer of coal,small changes in its projected demand growth rate have a large impacton global coal demand. If China is assumed to source its additional coaldemand from indigenous sources, projecting higher demand growth forChina means that a higher percentage of global coal supply will comefrom China in the USDOE projection than in the IEA projection.

Note that the EU projection does not separate out the threedifferent parts of Asia, namely China, East Asia and South Asia. TheEU’s aggregate Asian growth rate has therefore been shown in theabove table for all three Asian regions.

Another interesting feature of the above table is the much slowergrowth rate in OECD North America’s coal demand in the USDOEprojection than in the IEA projection. This difference arises mainlyfrom the fact that the IEA has matched North American gas demandwith supply. The result of that analysis (see Chapter 8 for details)implies an increase in the North American gas price. A consequence ofthis approach is that the IEA projection contains higher coal demandbut lower gas demand than does the USDOE projection.

Table 9.7: Total Primary Energy Supply (1995 - 2020)Annual Growth Rates

USDOE EU (1990 - 2020) IEAReference Case CW BAU Projection

Scenario

OECD 0.8% 0.2% 1.2%North America 1.2% n.a. 2.1%Europe 0.1% n.a. -0.6%Pacific 0.6% n.a. 0.5%Non-OECD 2.8% 1.6% 2.7%Transition Economies -0.6% -1.4% 0.7%Africa 0.9% 3.1% 2.1%China 4.3% 2.4% 3.1%East Asia 1.8% 2.4% 3.9%South Asia 2.5% 2.4% 3.7%Latin America 2.4% 3.7% 3.5%Middle East 2.6% 4.4% 5.0%World 2.1% 1.1% 2.2%

Chapter 10 - Biomass 157

CHAPTER 10BIOMASS

1

IntroductionBiomass energy currently represents approximately 14% of world

final energy consumption, a higher share than that of coal (12%) andcomparable to those of gas (15%) and electricity (14%). Indeveloping countries

2, in which three-quarters of the world’s

population live, biomass energy (firewood, charcoal, crop residues andanimal wastes) accounts, on average, for one-third of total final energyconsumption and for nearly 75% of the energy used in households.For large portions of the rural populations of these countries, and for

Figure 10.1: Per Capita Biomass versus per Capita GDPin Developing Countries

$ at 1990 prices and PPP per capita

0 2000 4000 6000 8000 10000 12000 14000 16000

800

700

600

500

400

300

200

100

0

kgoe

per

cap

ita

1. The IEA has organised two workshops on biomass energy. See Biomass Energy: Key Issues andPriority Needs. Conference Proceedings, IEA/OECD, Paris, 1997, and Biomass Energy: Data, Analysisand Trends. Conference Proceedings, IEA/OECD, Paris, forthcoming. The IEA has receivedfinance and support for this work from NUTEK (the Swedish National Board for Industrial andTechnical Development) and the European Commission (Directorate General XII).2. In this chapter, we define (developing countries) as the non-OECD countries of Africa, Latin Americaand Asia. Geographic coverage of each regional grouping is provided in the Definitions in Part IV.


the poorest sections of urban populations, biomass is often the onlyavailable and affordable source of energy for basic needs such ascooking and heating. Although biomass energy is predominantly usedin households, it also provides an important fuel source for traditionalvillage-based industries, as well as for many small- to medium-scaleservices and industries in and around cities

3.

The importance of biomass in the economy and in the householdsector varies widely across countries and regions, broadly reflectingtheir level of economic development (see Figure 10.1).

The share of biomass in final energy consumption is generallylower in countries with higher levels of income and industrialisation.On the other hand, in countries with low per capita incomes, whichare predominantly rural and rely heavily on subsistence agriculture,this share can reach 80% and more (for example Ethiopia, Mozambique,Tanzania, Democratic Republic of Congo, Nepal and Myanmar).

In spite of its significance at world level and its vital importancefor developing countries, biomass is often treated as a footnote item bymost sources of global energy statistics. This exclusion is usuallyjustified on the grounds that data on traditional biomass are too scarceand unreliable to be presented alongside commercial energy data

4. For

the same reason, biomass has been largely excluded from analyses ofglobal energy demand trends. The omission of such a critical anddominant fuel has several important implications leading to potentiallyserious shortcomings in global analysis

5. First, it substantially

understates the actual level of energy consumption of developingcountries. Second, the omission of biomass not only affects the levelbut also the rate of change of indicators such as energy intensity and percapita energy consumption, giving misleading indications in cross-national or inter-temporal comparisons. Third, in projecting futureenergy trends, the dynamics of the inter-fuel substitution from biomassto commercial energy cannot be captured and quantified. This sets animportant limitation on the reliability of long-term energy demandprojections for developing countries,and for the world in general.

3. See Hall, D.O. (1991), Biomass Energy, Energy Policy, Vol.19, No.10.4. For example, the BP Statistical Review of World Energy does not include biomass, with theargument that “fuels such as wood, peat and animal waste, though important in many countries,are unreliably documented in terms of consumption statistics” (British Petroleum, BP StatisticalReview of World Energy, British Petroleum Company plc, London, June 1998).5. See World Energy Outlook, 1996 Edition, IEA/OECD, Paris; and Guerer, N. (1997),Implications of Including Biomass in Global Energy Analysis, in IEA, Biomass Energy: Key Issuesand Priority Needs. Conference Proceedings, IEA/OECD Paris, 1996.


DefinitionsDiscussions of biomass are often clouded by problems of

definition. Several “labels” are used to refer to the same concept, ortightly overlapping ones: biomass fuels (or biofuels), non-commercialenergy, traditional fuels, etc.

The IEA uses the term combustible renewables and waste (CRW)to include all vegetable and animal matter (biomass) used directly orconverted to solid fuels, as well as biomass-derived gaseous and liquidfuels, and industrial and municipal waste converted to energy. Inpractice, there is limited use of municipal or industrial waste forenergy in developing countries. The main biomass fuels are fuelwood(or firewood), charcoal, agricultural residues and dung.

It is incorrect to equate biomass with non-commercial fuels,because an increasing share of fuelwood and practically all charcoal istraded. In many developing countries these markets rival electricitysales in monetary value. Similarly, the terms traditional as opposed tomodern or efficient fuels are misleading because the same fuel (e.g.fuelwood) can be used in a traditional three-stone cooking stove or ina modern industrial boiler to generate electricity or heat. Althoughthe majority of biomass energy use in developing countries is still inthe form of direct combustion of unprocessed solid fuels, theproportion of biomass being used in larger-scale industries (such aspulp and paper and agro-industries) and in other “modern” processes,such as electricity generation and the production of transport fuels, issteadily growing.

In this study, the term “biomass” is used to designate theaggregate combustible renewables and waste. All other non-biomassfuels are referred to as conventional fuels; these include fossil fuels aswell as electricity and non-combustible renewables (hydro,geothermal, wind and solar).

Data AvailabilityNational biomass statistics are inadequate both in quantity and

quality. Official sources frequently restrict themselves to the marketed(and therefore more easily measurable) component of the energypicture. In developing countries, there is often a lack of expertise aswell as financial and human resources for adequate data collection andestimation, a task rendered more difficult by the decentralised (mostlyrural) and largely non-marketed nature of biomass energy use. As aconsequence, in many countries, the data available are at best


estimates or extrapolations based on partial consumption studies, asregular country-wide surveys are extremely costly.

The statistics of the Food and Agriculture Organisation (FAO),although extensively used as the best available data at a macro level fora large number of countries, provide data only for fuelwood andcharcoal. These are based mainly on the availability of forestryresources

6and thus ignore a substantial amount of informal wood-

gathering in rural areas. Furthermore, time-series by the FAO areestimates often based on simple relationships with population. UnitedNations energy statistics draw largely on FAO data for firewood,adding estimates of other biomass fuels, such as agricultural residues,animal waste, and other waste (e.g. municipal, pulp and paper)

7.

Information on biomass use can also be found in an increasingnumber of detailed, ad-hoc surveys carried out by various regional orinternational organisations and independent researchers. While thesestudies may give interesting indications as to the local situation, theyare generally limited in time and scope, and do not generally covernon-household biomass energy.

The lack of uniform definitions and the use of different units andconversion factors, make aggregation and comparison of data fromdifferent sources a hazardous task. Problems of data quality may alsoarise from insufficient coverage, both geographical and temporal.Biomass energy consumption levels can vary significantly, even in arelatively small geographical area. Thus, the extrapolation to nationallevel of data collected in a small number of villages may lead toerroneous conclusions. Similarly, the extrapolation to a whole year ofdata collected at a certain time of the year can be very misleading. Thetypes and quantities of biomass fuels used can vary significantlyaccording to the time of the year, because of changing supply availability(abundance of certain crop residues at the time of harvesting) orchanging demand due to seasonal temperature variations or social andreligious behaviours. As a result, there may be considerablediscrepancies among country figures compiled from different sources.

Finally, most surveys tend to give a “point-in-time” picture ofbiomass use, with little or no indication of historical trends. Coherenthistorical series, necessary for the dynamic assessment of biomass use,are available only for a few countries.

6. FAO Yearbook of Forest Products, FAO, Rome, annual.7. The United Nations Statistics Database, United Nations Statistical Office (UNSO), New York,annual.


If consumption figures are uncertain, data on biomass supply andresources, which are necessary to determine whether biomass energyuse is sustainable or not, are even more sparse and inadequate. As aresult, the analysis of biomass fuel scarcity is largely based on anecdotalinformation and secondary indicators, such as the time spent in fuelcollection, distance travelled and purchases of alternative fuels.

The IEA Biomass DatabaseFor the first time, the IEA has prepared a database for biomass

energy use in non-OECD countries. Data are included for more than 100non-OECD countries. Wherever possible, data are disaggregated into fivemain product categories and more than 30 individual products. Sectoraldisaggregation follows IEA statistical conventions for conventional fuels.Historical data generally do not amount to coherent time series, as theyusually come from different sources or have been obtained with differentmethodologies. Where historical series are incomplete or unavailable,data have been estimated.

8The biomass database is updated on a regular

basis, and its contents are published annually in the IEA series EnergyStatistics and Balances of Non-OECD Countries.

From the IEA Biomass Database it is possible to extract two typesof data-set for use in the analysis:

• Figures of biomass consumption for the latest available year formore than 100 non-OECD countries, allowing cross-countrycomparisons and tests.

• Time series of consistently collected primary data for a numberof countries (mostly Latin American countries and a few Asianand African countries), which may be used in regression analysisto estimate relationships between biomass energy use andselected driving variables.

Basic Framework and Key Assumptions

General ObservationsThe literature at hand and the data available suggest that:• Biomass in general accounts for a smaller share of energy

consumption in countries with a higher per capita income. Theamount and type of biomass energy used is very site-specific and

8. See the 1998 edition of the IEA’s Energy Statistics and Balances of Non-OECD Countries, fordetails on methodology and coverage.


influenced by many non-income-related factors, such as climate,geography, land use, preferred foods and cooking techniques,availability and price of different conversion equipment (stoves),availability and reliability of supply of alternative fuels and theirrelative costs, socio-economic organisation, culture andtradition.

• A common theory in household energy analysis is that of the“energy transition” along a “fuel ladder”. It suggests that, withsocio-economic development, households move up their “ladderof fuel preferences” from low-quality fuels, such as biomass, tomore convenient, efficient fuels, such as kerosene, bottled gasand electricity

9.

• Although evidence exists for the presence of an energy transitionin the household sector, the decline of the share of biomass inthe energy mix accompanying economic development is mainlydue to the rapid growth of the industrial, transport and othersectors which rely on conventional fuels. Indeed, in manycountries total biomass consumption is still increasing and insome countries, even per capita biomass use is still growing.

• Availability and accessibility of biomass fuels is an importantfactor determining levels of consumption in rural areas.Availability also influences prices of biomass fuels in urban areas.

• It is important to distinguish between rural and urban areas, aspatterns and determinants of energy use are fundamentallydifferent in these two environments. This is because:

- In rural areas, biomass fuels are mainly collected by users, whereasin urban areas they are mostly marketed. The importance ofincome and relative fuel prices arises mainly in urban areas.

- The availability of alternative conventional fuels is oftenlimited or unreliable in rural areas.

- Substitution processes may differ substantially in urban andrural areas. When a given biomass fuel becomes scarce,people may go up the “fuel ladder” in urban areas, but downthe “fuel ladder” in rural areas.

- Finally, when increases in GDP are accompanied by aworsening of income distribution, the benefits of economicgrowth do not reach rural areas, where the large majority of

9. See Leach, G., The Energy Transition, Energy Policy, February 1992, and Davis, M., RuralHousehold energy consumption: The effects of access to electricity, evidence from South Africa, EnergyPolicy, February 1998.


biomass use is concentrated.• It is important to distinguish between different types of biomass

fuels (wood, charcoal and others). In fact:- Substitution between biomass fuels may be a more general

phenomenon than substitution with conventional fuels,especially in rural areas. For example, a reduced availabilityof woody biomass may not necessarily lead to an increasinguse of alternative conventional fuels, because there may be aswitch to a lower-quality but freely available biomass fuel,such as crop residues or dung.

- “Intra-biomass” substitutions are not 1-to-1 switches,because different biomass fuels are used in stoves withdifferent efficiencies.

- In the case of substitution of charcoal for wood and otherresidues (which is often a consequence of urbanisation,especially in Africa), total final consumption of biomass maydecrease because of the higher end-use efficiency andcalorific value of charcoal. But the low energy efficiency ofthe techniques used in many countries to produce charcoalwill inevitably result in an increase in the amount of primarywood used.

Methodological ApproachPrimary supply of biomass is calculated by adding the following

three components:• final end-use consumption of biomass;• biomass used for electricity and CHP generation;• losses in charcoal production, i.e. the difference between the

energy content of the wood input and that of the charcoal output.Following the approach used for conventional fuels, biomass

inputs in power generation (including CHP) are analysed separately(see Chapter 6) from end-use consumption. The calculation of lossesin charcoal production involves ad-hoc assumptions on the evolutionof the share of charcoal in biomass consumption, as well as on thecurrent and future efficiency of the charcoal transformation process,which is high in Brazil and lower in Africa and Asia. The approachused for projecting final consumption of biomass is described below.

As in the case of conventional fuels, the analysis and projectionsfor biomass demand are prepared on a regional basis. This involvesaggregating countries which are very different in many aspects. The


following discussion concerns the five regions that have a high share ofbiomass use: Africa, Latin America, China, East Asia and South Asia

10.

Biomass is not a homogeneous fuel. It differs widely in itsoriginal forms and production techniques. Solid, liquid and gaseousfuels can be produced from dry and wet feedstocks. Furthermore, it isused in a variety of processes with a large range of efficiencies. Thelevel of geographical aggregation and the problems of data quality andavailability limit the degree of detail in the analysis and “biomass” isconsidered here as a single fuel with a single end-use

11.

With these limitations in mind, several methods and approacheshave been explored, but no single approach was found suitable for allregions. The methodology used is therefore mainly an assumption-driven accounting framework.

In order to isolate the effect of growing population, per capitabiomass consumption was chosen as the dependent variable. Thevariables most likely to influence it are:

• available income (GDP per capita)• level of conventional energy use• price of alternative fuels (where available, the domestic price of

LPG, kerosene, diesel and fuel oil, or a weighted average of allthese - otherwise, world oil price as a proxy)

• share of urban population• availability of supply of biomass fuels• price of final biomass fuelsThe choice of quantitative measures for the above variables was

determined by the possibility of obtaining readily available projectionsover the period 1995-2020. For this reason, for example, we use GDPper capita rather than household income.

It proved very difficult to find a simple quantitative measure for“availability of supply of biomass fuels” for a large number of countries.While shortages may constrain biomass consumption locally (or, moreoften, induce shifts in the type of biomass used), it is not clear whateffect local shortages would have on aggregated biomass consumptionat national level (this is especially true for very large countries, such asIndia, China, or Indonesia). To account for the large differences ingeography that could have an impact on the supply of biomass, we havetried to include the “share of forested land” as a proxy.

10. See Definition in Part IV.11. Except for Latin America, where we distinguish biomass energy used in the industrial sectorand in other sectors (mainly households, but also agriculture and small services).


Assumptions on the levels of parameters, such as elasticities, fuelshares and growth rates, were derived from:

• econometric tests on countries with sufficient biomass data timeseries

• an analysis of socio-economic structure• conventional energy developments• other studies• cross-country analysis (classification methods, principal

components analysis)• expert judgement.Using available historical series for a number of Latin American

and Asian countries, and one or two countries in Africa, severalequations were estimated to test the relationships between the level ofbiomass per capita, or the share of biomass in total energyconsumption, and different sets of determining variables.

It was found that the most important variable is per capitaincome, while the price effect (the price of alternative fuels) wasgenerally small or insignificant. This is largely due to the fact thatmost biomass is used in rural areas, where prices are generally notrelevant. Urbanisation was found to be too highly correlated withincome to be included in the equations.

The levels and arithmetic signs of the coefficients were asexpected. Income elasticities were found to be negative (but smallerthan 1), implying that per capita use of biomass decreases as per capitaincome increases. Price elasticities (for the price of competing fuel),when significantly different from zero, were found to be positivethough small, implying that per capita biomass use will grow if theprice of the competing fuel increases (for example if subsidies wereremoved).

Econometric tests on the cross-country data-set confirmed theseresults, while classification methods and principal componentsanalysis showed that the regional groupings are homogeneous,although with a few overlapping areas and some outliers.

The values chosen for the elasticities in future years are based onthe econometric results above, as well as on a critical review of theavailable literature. They are not constant but vary throughout theprojection period to reflect the changing economic and energystructure.

The methodology for Latin America is slightly different from thatused for the other regions, because disaggregated historical series are


available. Since in Latin America the share of biomass use in theindustrial sector is significant, industrial biomass and non-industrialbiomass were projected separately. The elasticities for both theindustrial and household models are based on a combination ofeconometric analysis and expert judgement.

The key underlying assumptions on economic and demographictrends, as well as on the evolution of fossil fuel prices are the same asthose used in the conventional energy model

12. The resulting trends in

terms of regional per capita income levels are illustrated in Table 10.1.

Table 10.1. Per Capita GDP, Levels and Growth Rates13

Summary of Results

Final ConsumptionProjections of biomass energy consumption are shown in Table

10.2. Final consumption of biomass in developing countries isprojected to continue to increase, rising from 825 Mtoe in 1995 to1071 Mtoe in 2020, although at a lower rate than population and amuch lower rate than conventional energy use.

This rising trend is, broadly speaking, the result of twocontrasting trends. On one hand, the expected growth in average per

$ at 1990 prices andPPP per capita 1995 2000 2010 2020

China 2822 4029 6143 8933East Asia 4259 4987 6929 9600South Asia 1271 1432 1863 2433Latin America 5510 6105 7489 9022Africa 1521 1503 1496 1542

Average AnnualGrowth Rate (%) 1971-1995 1995-2000 2000-2010 2010-2020

China 6.9 7.4 4.3 3.8East Asia 4.8 3.2 3.3 3.3South Asia 2.3 2.4 2.7 2.7Latin America 1.2 2.1 2.1 1.9Africa -0.1 -0.2 -0.1 0.3

12. See Chapter 2 for a detailed discussion of GDP, population and fossil fuel prices assumptions.13. Attention is drawn in Chapters 2 and 15 to the difficulties encountered in measuring andprojecting gross domestic product in China.


capita GDP is assumed progressively to lead to lower per capitabiomass use, as people, especially in urban areas, gradually switch toconventional fuels, and biomass end-use efficiency slowly increases.On the other hand, the still significant rate of population growthmeans that an increasing number of people will use biomass, drivingup total consumption.

The rate of growth of total biomass consumption is relatively lowand slowing down: it is projected to be 1.2% between 1995 and 2000,1.1% between 2000 and 2010 and 1% between 2010 and 2020.

During the same periods, final consumption of conventional fuelsis projected to grow at much faster rates (4.3%, 3.5% and 3.1% perannum respectively), so that the share of biomass in total finalconsumption will decline from 34% in 1995 to 22% in 2020. Thereare significant regional differences in the rates of growth and resultingshares, as illustrated in Table 10.2. Consumption of biomass isexpected to grow much faster in Africa (2.4% per annum) than inother regions, as a result of sluggish economic growth, rapidlyincreasing population and relatively low growth in conventional fuelconsumption.

Adding to these figures and projections those for combustiblerenewables and waste (CRW) consumption in OECD regions, as wellas rough estimates of CRW consumption in the Transition Economiesand in the Middle East, world biomass consumption is projected togrow from 930 Mtoe to 1193 Mtoe between 1995 and 2020. Its sharein total final energy consumption will decrease from 14% to 11%.

Power GenerationBiomass-fuelled power generation is still marginal in developing

regions, but it is projected to rise rapidly, nearly tripling during theforecast period from 10 TWh in 1995 to 27 TWh in 2020.Accordingly, biomass inputs in power (and CHP) generation will alsotriple from 4 Mtoe in 1995 to 12 Mtoe in 2020. The share of biomassin total electricity generation does not rise, however, because of theeven more rapid increase of other types of power generation. Mostbiomass-fuelled power generation is concentrated in Latin America.Projections of power generation are discussed in Chapter 6.

Charcoal ProductionCharcoal is a secondary product, included in the final

consumption of biomass. For the calculation of the primary supply of


Annu

al Gr

owth

Rate

(%)

1995

2020

1995

-202

0

Biom

assCo

nven

tiona

lTo

talSh

are of

Biom

assCo

nven

tiona

lTo

talSh

are of

Biom

assCo

nven

tiona

lTo

tal

Energ

yBi

omass

Energ

yBi

omass

Energ

y

Chi

na20

664

985

524

%22

415

2417

4813

%0.

33.

52.

9

East

Asia

106

316

422

25%

118

813

931

13%

0.4

3.8

3.2

Sout

h A

sia23

518

842

356

%27

652

379

935

%0.

64.

22.

6

Latin

Am

eric

a73

342

416

18%

8170

678

710

%0.

42.

92.

6

Afri

ca20

513

634

160

%37

126

063

159

%2.

42.

62.

5

Tota

l dev

elop

ing

coun

trie

s82

516

3224

5634

%10

7138

2548

9622

%1.

03.

52.

8

Oth

er n

on-O

ECD

2410

3710

611%

2616

6916

951%

0.3

1.9

2.8

Tota

l non

-OEC

D84

926

6935

1824

%10

9754

9465

9117

%1.

02.

92.

5

OEC

D c

ount

ries

8130

4431

253%

9638

7239

682%

0.7

1.0

1.0

Wor

ld93

057

1366

4314

%11

9393

6510

558

11%

1.0

2.0

1.9

Tabl

e 10.

2. T

otal

Fin

al E

nerg

y Su

pply

incl

udin

g Bi

omas

s En

ergy

(Mto

e)


biomass it is necessary to know the amount of wood used in charcoalproduction. For many countries, this amount is not known, so thatassumptions have to be made on the efficiency of the charcoaltransformation process.

Available data and estimates for 1995 show that charcoalconsumption in developing countries amounted to approximately 22Mtoe, roughly equally divided between Africa, Asia and LatinAmerica. Most of charcoal use in Latin America is concentrated inBrazil (5 Mtoe), where it is produced in large, highly efficient modernkilns and used mainly in the production of steel. In Africa and Asia,charcoal is largely produced with traditional techniques, in smallvillage kilns with low transformation efficiencies, and used in thedomestic sector, especially in urban areas. Thailand accounts for 65%of charcoal use in Asia and is one of the countries with the highestshare of charcoal in biomass consumption in the world (39%). InChina, charcoal use is virtually non-existent because of the extensiveuse of coal briquettes.

Table 10.3. Charcoal Production (Mtoe)

Future charcoal use and wood inputs into charcoal productionwere calculated using ad-hoc assumptions on the evolution of theshare of charcoal in biomass consumption and the efficiency of thetransformation process. The share of charcoal in biomassconsumption is expected to rise in all regions as a result of the switchin cities from wood and agricultural residues to charcoal, which is amore convenient fuel and more economical to transport over long

1995 2010 2020 1995 2010 2020

East Asia South Asia

Share in final biomass 5% 7% 8% 2% 3% 4%Charcoal production/use 5.6 7.8 9.2 3.5 7.9 11.1Wood input 16.5 21.7 25.1 12.6 28.2 39.5Losses in charcoal transformation 10.8 14.0 15.9 9.1 20.3 28.4

Latin America Africa

Share in final biomass 9% 9% 9% 3% 6% 8%Charcoal production/use 6.4 7.0 7.2 6.8 19.1 30.8Wood input 13.2 14.5 14.9 27.0 72.1 112.1Losses in charcoal transformation 6.8 7.5 7.7 20.3 53.0 81.3


distances than wood. The resulting projections are summarised inTable 10.3 below.

Primary Energy SupplyPrimary consumption of biomass has been calculated by adding

final end-use consumption of biomass (including charcoal), biomassused for electricity and CHP generation and the energy losses incharcoal production.

Primary consumption of biomass in developing countries isprojected to increase from 876 Mtoe in 1995 to 1216 Mtoe in 2020,at an average of 1.4% per annum. This is a slightly higher growth ratethan that for final consumption due to the rapidly increasing, thoughstill small, use of biomass in electricity generation and the increasinguse of charcoal. Table 10.4 shows the projections by region.

Adding the OECD, Transition Economies and Middle Eastregions, world primary consumption of biomass is expected to growfrom 1046 Mtoe to 1418 Mtoe between 1995 and 2020. Its share intotal final consumption will decrease from 11% to 9%.

More details on biomass consumption in each region are given inthe chapters in Part III.

Uncertainties and LimitationsThe uncertainties and limitations linked to these projections are

substantial, mainly due to problems of data availability and quality. Asa result, the figures presented in this chapter should be read asindications of the orders of magnitude involved and the changingpatterns that can be expected.

The main objective of the exercice was to demonstrate theimportance of including biomass in global energy analysis, andillustrate the shortcomings deriving from its exclusion. Theintegration of the analyses and projections of conventional andbiomass fuels provides a more complete picture of future energy trendsin developing countries and allows a better understanding of thedynamics of the transition from non-commercial biomass tocommercial fuels. It is hoped that better data and furtherinvestigation will become available so that this work may be deepenedand extended.


Annu

al Gr

owth

Rate

(%)

1995

2020

1995

-202

0

Biom

assCo

nven

tiona

lTo

talSh

are of

Biom

assCo

nven

tiona

lTo

talSh

are of

Biom

assCo

nven

tiona

lTo

tal

Energ

yBi

omass

Energ

yBi

omass

Energ

y

Chi

na20

686

410

7019

%22

421

0123

2510

%0.

33.

63.

2

East

Asia

117

464

581

20%

136

1275

1411

10%

0.6

4.1

3.6

Sout

h A

sia24

428

452

846

%30

881

111

1928

%0.

94.

33.

0

Latin

Am

eric

a83

452

535

16%

9598

610

819%

0.5

3.2

2.8

Afri

ca22

522

645

150

%45

343

288

651

%2.

82.

62.

7

Tota

l dev

elop

ing

coun

trie

s87

622

9131

6628

%12

1656

9662

2116

%1.

33.

63.

1

Oth

er n

on-O

ECD

2814

4914

771%

3022

2822

580%

0.3

1.7

3.1

Tota

l non

-OEC

D90

437

3946

4319

%12

4678

3390

8014

%1.

33.

02.

7

OEC

D c

ount

ries

142

4330

4473

3%17

255

3557

073%

0.8

1.0

1.0

Wor

ld *

1046

8199

9245

11%

1418

1357

714

995

9%1.

22.

02.

0

Tabl

e 10.

4.To

tal P

rim

ary

Ener

gy S

uppl

y in

clud

ing

Biom

ass

Ener

gy (M

toe)

* In

clud

es m

arin

e bu

nker

s.

PART III

OUTLOOK FOR WORLD REGIONS


Chapter 11: OECD Europe 175

CHAPTER 11OECD EUROPE1

IntroductionIn 1995, OECD Europe accounted for 35% of OECD’s and

19% of the world’s primary commercial energy demand. OECDEurope’s share of world energy demand, in the business as usualprojection, declines to 15% by 2020 as energy demand in the non-OECD regions grows more rapidly. The main assumptions used inderiving OECD Europe’s energy projections are shown in Table 11.1.A static population results in GDP and per capita income growingtogether by almost two-thirds between 1995 and 2020 providingupward pressure on energy demand. In most other regions of theworld the population is assumed to grow, consequently per capitaincomes rise less quickly than GDP.

Table 11.1: Assumptions for OECD Europe

Energy Demand OutlookTotal primary energy demand is projected to grow, in the BAU

1. OECD Europe in this Outlook comprises the following 21 countries: Austria, Belgium, CzechRepublic, Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy,Luxembourg, Netherlands, Norway, Portugal, Spain, Sweden, Switzerland, Turkey and the UnitedKingdom. Poland acceded to the OECD on 22 November 1996 but, at the time of writing,Poland’s historical data had not been incorporated into official IEA energy statistics. Furtherdetails can be found on page XXXI of the OECD/IEA publication Energy Balances of OECDCountries 1994-1995, 1997.2. Some revisions to historical data may be made in future years, especially on the inclusion ofdata from Eastern European countries.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal Price ($1990 per metric ton) 44 40 42 46 0.5%Oil Price ($1990 per barrel) 6 15 17 25 2.1%Natural Gas ($1990 per toe) n.a. 90 103 150 2.1%GDP ($Billion 1990 and PPP) 3929 6965 9803 11524 2.0%Population (millions) 410 466 472 468 0.0%GDP per Capita ($1990 and PPP 9587 14944 20774 24640 2.0%per person)


projection, at an annual average rate of 1.1% between 1995 and 2020.Other (non-hydro) renewables are the most rapidly growingcomponent of TPES, at an annual average rate of 5.1%, from a lowbase in 1995. Gas is projected to be the most rapidly growing fossilfuel with an annual average demand growth rate of 3%, compared to1.1% for oil and -0.3% for solid fuels. Hydro power grows at anannual average rate of 1% during the projection period.

Table 11.2: Total Primary Energy Supply (Mtoe)

Total Final Energy ConsumptionTotal final energy consumption (TFC) is projected to grow at an

annual average rate of 1.3% between 1995 and 2020. Coal demandremains virtually unchanged, although there will be some variations inintra-regional composition. Electricity is the most rapidly growingenergy type within TFC and grows at slightly more than the averagerate of GDP growth. Among the fossil fuels, oil grows most quickly, atan annual average rate of 1.2%. This growth is mainly driven bydemand for mobility-related energy, growing at an annual average rateof 2.3%. The demand for gas rises at a modest rate of 0.8%, reflectingthe fact that the demand for energy in the stationary sector (excludingelectricity) grows slowly during the projection period. With relatively flatprojected demand for fossil fuels in the stationary sector, a large portionof the growth in gas demand arises from substitution for coal and oil.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TPES 1151 1554 1944 2046 1.1%Solid Fuels 370 331 371 310 -0.3%Oil 652 650 779 850 1.1%Gas 86 301 506 625 3.0%Nuclear 13 225 225 190 -0.7%Hydro 28 42 50 54 1.0%Other Renewables 2 4 11 16 5.1%Other Primary 0 1 1 1 0.0%


Figure 11.1: Total Primary Energy Supply in OECD Europe

Table 11.3: Total Final Energy Consumption (Mtoe)

* Includes renewables.

Stationary Sectors3

Stationary uses of fossil fuels are projected to remain essentiallyflat over the projection period, as they have been since the early 1980s.

3. Stationary uses are all non-electricity consumption in the following final consumption sectors - industry,agriculture, commercial, public services, residential, non-specified and non-energy uses. It can be calculated as TotalFinal Consumption less Total Final Electricity Consumption less Total (non-electricity) Transport Consumption.

1971 1980 1990 2000 2010 20200

500

1 000

1 500

2 000

2 500

mill

ion

tonn

es o

il eq

uiva

lent

Oil

Gas

Solid Fuels

Nuclear Hydro & Other Renewables

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TFC 887 1120 1403 1529 1.3%Solid Fuels 196 109 106 109 0.0%Oil 523 567 701 768 1.2%Gas 71 225 280 274 0.8%Electricity 95 195 280 329 2.1%Heat* 3 23 36 48 2.9%


This projection reflects the saturation of residential space and waterheating in some OECD Europe countries and the continuing trendtowards less energy-intensive industries. The consumption of oil instationary uses is projected to continue to decline. Gas increasinglysubstitutes for oil with the result that 75% of the projected increase ingas demand during the period 1995 to 2020 arises from oil-to-gassubstitution. Around a third of the total increase in demand is met bygas with the remainder met by heat in district heating systems andsales of steam in industry. The consumption of heat is projected togrow at 2.9% per annum, with the increased use of combined heat andpower units being a major factor in increasing projected heat demand.

Table 11.4: Energy Use in Stationary Sectors (Mtoe)


Figure 11.2: Fossil Fuel & Heat in Stationary Sectors

800

700

600

500

400

300

200

100

0

mill

ion

tonn

es o

il eq

uiva

lent

3000 4000 5000 6000 7000 8000 9000 10000 11000 12000GDP ($ Billion at 1990 prices and Purchasing Power Parities)

1971-1995 1996-2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 636 617 661 655 0.2%Solid Fuels 192 109 106 109 0.0%Oil 370 260 239 223 -0.6%Gas 71 225 280 274 0.8%Heat* 3 23 36 48 2.9%


Figure 11.3: Stationary Energy Uses by Fuel

Figure 11.4: Heating Degree Days

One of the difficulties in projecting energy demand in thestationary sectors is that much of the demand is sensitive to theweather. Energy demand for space heating in the residential and service

1971 1980 1990 2000 2010 20200

200

400

600

800

mill

ion

tonn

es o

il eq

uiva

lent Oil

Gas

Solid Fuels

Heat

2800

2700

2600

2500

2400

2300

2200

1971 1980 1990 2000 2010 2020


sectors are clear examples. Less obvious examples include energy usedin blast furnaces and kilns. During the period 1971 to 1996, theaverage number of heating degree days in OECD Europe was 25564,however, as Figure 11.4 indicates, the number of heating degree dayshas fallen sharply since 1987. Since that year, only 1991 has hadanything like a typical number of heating degree days. 1991 was clearlyexceptional as the eruption of Mount Pinatubo in the Philippines inthat year cooled the earth for about two years. Had Mount Pinatubonot erupted, the number of heating degree days may have been lowerand with it energy consumption.

Figure 11.5 provides an example of the broad relationshipbetween total fossil fuels demand in the stationary sectors and thenumber of heating degree days. A strong positive correlation betweenthe two series can be seen, despite the variations caused by changinglevels of GDP and energy prices.

Figure 11.5: Stationary Sectors Energy Demand 1971 - 1995

It should be clear from the discussion above that the heating-degree assumptions used in preparing the stationary sectors energyprojections can alter the results by as much as 10% over the range of2300-2700 heating degree days. The approach adopted here has beento examine the average number of heating degree days experienced up

4. Heating degree days are a measure of the extent to which the mean daily temperature falls below anassumed base temperature. The exact base temperature used in the calculation varies across countries.

740

720

700

680

660

640

620

600

mill

ion

tonn

es o

il eq

uiva

lent

Heating Degree Days

2200 2300 2400 2500 2600 2700 2800


until 1991 (inclusive) and to set the assumed future number withreference to this average for the period 1971 to 1991. This approachtherefore excludes the early years of the 1990s, during which thenumber of heating degree days was unusually low. If emissions ofgreenhouse gases are having a warming impact on the climate, assuggested by a number of climate change experts, then continuedgrowth in the demand for fossil fuels could result in a lower numberof heating degree days than assumed in this analysis. Were this tohappen then a downward adjustment to the stationary sectors’ fossilfuel demands would be required.

Mobility5

The increasing demand for mobility is a major reason for thegrowth in total oil demand in recent years. Since the demand fortransport-related services increases with income, and this relationshipshows no sign of ending, oil demand in OECD Europe and in manyother regions is becoming increasingly concentrated in the transportsector. The demand for road and aviation fuels has dominated thedemand for energy in the transport sector and is likely to continue todo so. The demand for road fuels will ultimately be limited by factorssuch as congestion and the saturation of vehicle ownership, but withinOECD Europe there exists a wide diversity of vehicle ownership levels.Merely raising car ownership levels in each country to the highestcountry level in OECD Europe would increase the demand for energyin this sector. Similarly, for aviation, although the number of aircraftmovements at an airport and traffic volume have an upper limit, theincome-related trend toward taking long-distance holidays by airwould increase energy demand unless there were offsettingimprovements in aircraft efficiency.

Table 11.5: Energy Use for Mobility (Mtoe)

5. Mobility includes all energy consumption in the transport sector except electricity and bunkers.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 157 308 462 546 2.3%

The total demand for mobility-related fuels (excluding electricity)continues the linear link with GDP established over the last 24 years.From Table 11.5, the annual growth rate of 2.3% for energy use inmobility is somewhat greater than the 2.0% annual average growthrate in incomes assumed for the projection period.

Figure 11.6: Energy Use in Mobility

Figure 11.7: Total Final Electricity Consumption (Mtoe)

350

300

250

200

150

100

50

0

mill

ion

tonn

es o

il eq

uiva

lent

GDP ($ Billion at 1990 prices and Purchasing Power Parities)

3000 4000 5000 6000 7000 8000 9000 10000 11000 12000

1971-1995 1996-2020


600

500

400

300

200

100

0

mill

ion

tonn

es o

il eq

uiva

lent

GDP ($ Billion at 1990 prices and purchasing Power Parities)

3000 4000 5000 6000 7000 8000 9000 10000 11000 12000

1971-1995 1996-2020


Total Final Electricity ConsumptionThe projected demand for electricity continues the link with

GDP established since 1971. During the period 1971 to 1995,electricity demand grew faster than GDP in OECD Europe (3.1%versus 2.4% per annum). During the period 1995 to 2020 therelationship is expected to be closer than in the past, with electricitydemand projected to grow at an annual average rate of 2.1%compared to the assumed GDP growth rate of 2.0%.

Table 11.6: Total Final Electricity Consumption (Mtoe)

Power GenerationElectricity generation in OECD Europe is projected to grow at an

average annual rate of 2.1%, increasing from 2678 TWh in 1995 to4492 TWh by 2020.

By 2020, the electricity generation mix in OECD Europe isprojected to be quite different from that of today. Most of theincremental demand for electricity is expected to be met by naturalgas, and its share in generation increases rapidly, from 10% at present,to 45% in 2020. Coal and nuclear power, which today are Europe’smost important sources of electricity, together supplying more than60% will decline to 34% in 2020.

Table 11.7: Electricity Generation in OECD Europe (TWh)

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 95 195 280 329 2.1%

1971 1995 2010 2020

Solid Fuels 557 828 997 801of which CRW 6 30 43 53Oil 316 237 214 230Gas 74 255 1131 2021Nuclear 51 861 863 729Hydro 320 486 585 629Wind 0 4 33 66Other 3 6 13 16Total 1322 2678 3836 4492


Until recently, coal was the most important source of electricitysupply in OECD Europe. It was overtaken by nuclear power in 1993.Coal accounted for 42% of electricity generation in 1971. By 1995, ithad fallen to 31% and is projected to fall to 18% in 2020. After aninitial increase in the period to 2010, coal-fired generation decreases,as older plants are retired. Although its significance in electricitygeneration decreases, coal is likely to maintain its position in base-loadgeneration, particularly as oil and gas prices begin to rise, making coalmore competitive. This position could only be threatened by furthertightening of environmental controls, responding to concerns aboutfuture emission levels of CO2 and sulphur dioxide.

Since 1971, the share of oil in the electricity-output mix has fallenfrom nearly one quarter to less than 10%. The first oil price shock in1973 effectively ended oil’s position as the least expensive powergeneration fuel6. Concerns in some countries about security of supplyalso contributed to oil’s decline. At current oil prices, heavy fuel oil istoo expensive for normal base-load generation, and its main use is indelivering power at peak periods in existing oil-fired boilers. In thefuture, oil distillates may play that role in new simple turbines. Oil isan ideal fuel for use in peaking plant or as a standby fuel in case ofemergency, as it has a low storage cost and the capital costs of turbineplant are also low. Over the Outlook period, electricity output fromoil is projected to continue to decrease slightly, with its share falling toaround 5%.

Nuclear power grew strongly in the 1970s and 1980s. The averageannual growth in the period 1971 to 1995 was 12.5%. In this period,nuclear power was perceived as economically viable and as enhancingthe security of supply of electricity. Nuclear power increases slightly inthe late 1990s, as new stations in France and the Czech Republic arebrought on line, while existing plants are upgraded and operate athigher capacity factors. After 2010, nuclear power plant retirementsare frequent, as nuclear plants reach their assumed 40-year lifetime.

Hydroelectricity increases by 1% per annum. Most hydro sites inOECD Europe have already been exploited. Currently, there is littleactivity in new hydro building, but small capacity additions in severalcountries of the region could lead to a 29% increase in hydroelectricgeneration. The largest additions are expected in Turkey, which hassignificant untapped hydro resources and a rapidly growing electricitysector.

6. Oil in Power Generation, IEA/OECD Paris, 1997.


Other renewable energies are growing fast, although from a verylow basis. The most significant increase is expected in wind power,which could grow from 4 TWh in 1995 to 66 TWh in 2020. Theshare of non-hydro renewable energy for electricity generation will stillremain low, at about 1.8% of total electricity generation in 2020.

Electricity generation from combined heat and power (CHP)plants is projected to grow at around 3% per annum. In 1995, CHPplants generated 243 TWh of electricity, which was about 9% of totalelectricity generation. By 2020, this figure could rise to 508 TWh andcould account for 11% of total generation. Heat output from CHPplant increases from 17.4 Mtoe in 1995 to 42.2 Mtoe by 2020.

Electricity Generating CapacityInstalled capacity in OECD Europe is projected to increase by

1.9% per annum in the period 1995 to 2020. The growth in capacityis less than the growth in electricity demand. This is due partly tocurrent excess capacity in OECD Europe, because of overbuilding inthe 1980s. In the projected capacity mix there is less hydro power andmost new capacity is in CCGT plant, with high availability comparedto that of a coal fired plant.

Table 11.8: Electricity Generating Capacity by Fuel (GW)

Most new capacity is expected to be natural gas-fired, particularlyin combined cycle gas turbine (CCGT) plants, because of theireconomic and environmental advantages.

As shown in Table 11.9, installed CCGT capacity in OECDEurope has increased rapidly over the past few years.

1995 2010 2020

Solid Fuels 173 160 129of which CRW 6 8 10Oil 84 82 80Gas 75 279 459Nuclear 126 127 107Hydro 167 188 201Of which Pumped Storage 30 32 34Wind 2 15 30Other 2 3 4Total 628 853 1009


Table 11.9: Combined Cycle Gas Turbine Capacity (MW)

Source: IEA data.

There are a number of reasons for the new popularity of gas. Thelifting of the European Commission’s ban upon the use of natural gasfor power generation was a significant factor. It coincided with aneconomic and political climate favourable to the expansion of gas firedgeneration. The economics of power generation have moved in thedirection of natural gas as has the requirement to fit pollution-controlequipment to coal-fired generation plants. This and the environmentaladvantages of natural gas have resulted in it becoming the preferredfuel for new power generation capacity across most of OECD Europe.

In addition, the increasing deregulation of electricity marketsfavours the use of gas in power generation, as smaller companiesentering the market will be attracted by the lower overall cost of gas-fired power generation and by the shorter lead times and lower capitalcosts. Many countries have announced plans to build more gas-firedcapacity, in both the public and private sectors.

Nuclear capacity in OECD Europe peaks around the year 2000,with the completion of new units, as shown in Table 11.10, and somecapacity upgrades in Finland, Belgium and Switzerland. After that,capacity decreases and falls to 107 GW in 2020, as the nuclear unitsthat were built in the 1970s are retired. It is assumed in this Outlookthat nuclear units are decommissioned after 40 years of operation.One should not, however, exclude the possibility that, in order toachieve emission reduction targets, some countries could extend thelives of their nuclear plants. On the other hand, some of Europe’snuclear plants may be retired earlier. Recently, the Dodeward BWR 55MW unit in the Netherlands was permanently shut down after 30years of operation. In France, the 1200 MW Superphenix fast breederreactor was shut down after 12 years of operation. The Swedish

1995 2010 2020

Belgium 186 1202 1196Italy 115 1508 2470Netherlands 1710 2255 4827Spain 936 967 1311UK 0 9185 12303Other 1203 2302 2565Total OECD Europe 4150 17419 24672


government has stated its intentions to phase out nuclear powerentirely by 2010, although this could create tension between satisfyingelectricity requirements and achieving other environmental objectives.The first two Swedish units to be retired were Barsebaeck 1 in 1998and Barsebaeck 2 in 2001. However, in the beginning of May 1998,the country’s Supreme Administrative Court ruled that thedecommissioning of the country’s oldest reactor could be unlawful.

Power station fuel requirements are projected to increase by 39%above their current levels. This is an average annual increase of 1.3%over the projected period and is substantially lower than growth inoutput. The power sector becomes more efficient as highly efficientCCGT plants are introduced. It is assumed that the efficiency of new combined cycle plant increases over time, from 52% at present to 60%in 2020. The average efficiency of coal burning increases from 34% to37%, as other less efficient units are retired, especially toward the endof the projection period. Natural gas requirements for electricitygeneration grow sixfold, from 55 Mtoe in 1995, to 319 Mtoe by2020. More than half the region’s total gas demand in 2020 isprojected to come from power stations. Solid fuel consumptionincreases from 208 Mtoe in 1995 to 250 Mtoe by 2010 and falls to184 Mtoe in 2020.

Figure 11.8: Fuels used in Power Generation in OECD Europe 1971-2020

Solid Fuels Oil Gas Nuclear Hydro Other Renewables


mill

ion

tonn

es o

il eq

uiva

lent

350

300

250

200

150

100

50

03000 4000 5000 6000 7000 8000 9000 10000 11000 12000

1971-1995 1996-2020


Table 11.10: Nuclear Plants Under Construction and Completed: 1995 - 2000

Source: Various industry sources.

Demand for oil products remains almost flat throughout the periodand represents a small share of the fuel mix, 8% in 1995, falling to 6%by 2020. The mix of oil used is expected to change towards lighterdistillates.

Oil7

In 1997 OECD Europe produced 6.7 million barrels per day(Mbd) of oil8. Of this total the UK and Norway together produced over6 Mbd. The overwhelming majority of the region’s oil production isfrom the North Sea. A recent IEA study of offshore prospects projectedthat UK offshore oil production would peak around 19999. The samepublication shows Norwegian offshore oil production peaking a yearlater in 200010. During early 1997, Norway announced an increase in itscombined oil and gas reserves. Most of this increase arose from theassumption that new technologies would improve the recovery factors ofnew and existing fields. It is too early yet to say how these newtechnologies might alter future Norwegian oil production profile, but, asthe oil production profiles considered in this WEO are based on a rangeof ultimate oil reserve estimates, it is reasonable to assume that the upperportion of the range incorporates Norway’s technology-induced reserveupgrades.

The oil balance for OECD Europe is shown in the table below,see Chapter 7 for further details.

7. The methodology used to derive the oil production projections can be found in Chapter 7.8. Table 1, April 1998 Oil Market Report, IEA/OECD.9. Table 11, page 44. Global Offshore Oil Prospects to 2000, IEA/OECD Paris, 1996.10. Ibid., Table 23, page 66.

Plant Name Capacity (MW) Country Year on Line

Sizewell B 1188 UK 1996Chooz B1 1455 France 1996Chooz B2 1455 France 1997Civeaux 1 1450 France 1997Civeaux 2 1450 France 1999Temelin 1 910 Czech Republic 1999


Table 11.11: OECD Europe Oil Balance (mbd)

Note: The above table includes all liquids.

Gas11

Indigenous gas production in OECD Europe was 199 Mtoe in1995. In addition, the region had net imports of 104 Mtoe. Some93% of OECD Europe’s gas production in 1996 was concentrated injust five countries; Norway (33%), UK (31%), Netherlands (14%),Germany (8%) and Italy (7%). OECD Europe’s share of world provengas reserves is relatively modest, at around 4%12. This region’s share ofultimate gas reserves13 was estimated by the USGS at 5.7% in 1993.The following table provides details of this estimate.

Table 11.12: OECD Europe’s Gas Reserves at 1/1/1993 - Trillion Cubic Feet (tcf)

Source: Masters C., Attanasi E. and Root D., US Geological Survey (USGS), World PetroleumAssessment and Analysis, in Proceedings of the Fourteenth World Petroleum Congress (New York,NY: John Wiley and Sons, 1994). World total ultimate gas reserves are estimated by the USGS tobe 11448 tcf. Note 1 Mtoe = (42.9 / 1000) tcf.

With the exception of OECD North America, OECD Europehas produced the highest percentage of its ultimate gas reserves of anyof the 10 regions examined here, some 28% by the end of 1995.Given the region’s modest remaining gas reserves and projected growthin gas demand of around 3% per annum, the scope for large gas

11. The methodology used to derive the gas production projections can be found in Chapter 8.12. See page I.44 of Natural Gas Information, July 1997, IEA/OECD Paris 1997.13. Ultimate reserves is the sum of cumulative production, remaining reserves (usually proven +probable) and estimated undiscovered reserves.

1996 2010 2020

Demand 14.4 17.0 18.7Supply 6.7 4.5 2.8Net Imports 7.7 12.5 15.9

Cumulative Production 160Identified Reserves 290Undiscovered 206Ultimate Reserves 656


imports into OECD Europe is considerable during the projectionperiod. It is assumed that gas production will grow at 2.2% per annumuntil 60% of OECD’s Europe ultimate gas reserves have beenproduced14. Production is then assumed to decline by 5% per annum.The resulting gas production projections are shown below.

Figure 11.9: Gas Balance for OECD Europe

Table 11.13: Gas Balance for OECD Europe (Mtoe)

Note: 1 Mtoe = (42.9 / 1000) tcf.

Based on Figure 11.9 and Table 11.13, it is clear that OECDEurope’s gas security of supply situation will alter radically during the

14. This estimated growth in OECD Europe’s gas production has been obtained from the analysis shown on page 75 ofThe IEA Natural Gas Security Study, IEA/OECD 1995. The analysis in that publication only examined the period 1992 to2010, but since OECD Europe’s gas production is projected to reach the 60% inflection point by 2015, using the samegrowth rate in production for the five years beyond 2015 is not an unreasonable assumption to make.

mill

ion

tonn

es o

il eq

uiva

lent

800

600

400

200

01995 2000 2005 2010 2015 2020

Net Imports

Indigenous Production

1995 2010 2020

Production 199 276 238Imports 164 290 447Exports -59 -59 -59Stock Changes -2 0 0TPES 301 506 625


projection period. Whereas in 1995 OECD Europe produced aroundtwo-thirds of the gas it consumed, and imported the remaining 35%,by 2020 the region will be importing over 70% of its gas requirements.

Coal15

In 1996, 140 million tonnes (Mt) of hard coal were produced inOECD Europe. Of this total Germany, Spain and France produced 77Mt16. Of the remaining 63 Mt, the majority was produced by theUnited Kingdom (49.8 Mt). In Germany and Spain, hard coalproduction remains heavily subsidised. In the UK, however, subsidiesfell by 95% between 1983 and 1995 as the government has sought toput the coal industry onto a commercial footing. During the sameperiod, German coal subsidies increased by 86%. In Spain, coalsubsidies increased by 142% during the period 1986 - 199517.

The amount of financial support that Governments are preparedto give to their indigenous hard coal industry will be a majordeterminant for the future of a substantial proportion of hard coalproduction in OECD Europe. In Belgium and Portugal, hard coalproduction has ceased, while in France production is planned to closeby the year 2005. In both Germany and Spain, pressures to maintainregional employment will inevitably mean that restructuring and thereduction of subsidies will remain politically contentious. However, inGermany the 1997 agreement between the Government, the affectedLänders, the coal companies and the trade unions to reduce subsidiesis expected to cut production from some 51 million tonnes in 1997 toabout 30 million tonnes by the year 2005. In Spain the Government hasannounced the continuation of subsidised coal production over the nextten years under the terms of a framework agreement for the electricitysectors, signed with national generators. This agreement, designed to phase-in deregulation, will continue to guarantee that the share of domestic coalused in power generation will be a minimum 15 percent (down from about40 percent currently). Production is currently planned to decrease from 18million tonnes in 1997 to 14.7 million tonnes by the end of 2001.

15. Information in this section is taken from the recent IEA publication International Coal Trade- The Evolution of a Global Market, IEA/OECD 1997.16. See page 95 op. cit.17. These figures refer to IEA estimates of Total Producers Subsidy Equivalent for coal production.See Table 15, page 106 op. cit.

As the amount of subsidies provided by Member governments havesuch a crucial impact on a major part of coal production in OECDEurope, it is not possible to provide firm projections of the level offuture production. Subsidies are likely to continue into the foreseeablefuture, for essentially social and regional reasons, but coal productionwill decrease significantly. An indication of the scope of possiblereductions can be seen from the fact that, whereas 77 million tonnes ofcoal was produced in Germany, Spain and France in 1995, only between10 and 30 million tonnes of this could be considered economic18.

OECD Europe’s hard coal imports trebled between 1968 and1995. This trend towards growing import dependence looks set tocontinue as domestic production declines. The introduction ofderegulation and Third Party Access rights in the European gas marketfrom 1999 will restrain coal demand and hence coal imports. Security-of-supply issues are less of a concern for coal than for either oil or gas,as coal reserves are much more widely dispersed than is the case for theother two fossil fuels. The following table indicates the geographicaldiversity of OECD Europe’s steam coal imports (101 Mt in 1996)19.

Table 11.14: OECD Europe 1996 Steam Coal Imports by Source (percentage)

The table above shows that no single region or country suppliesmore than a third of OECD Europe’s imports and so security ofsupply is not a significant concern. Furthermore, since excess capacityexists in the US and, to a lesser extent, in some other coal exportingcountries, an increase in coal prices is unlikely. Therefore, domestic

18. See page 96 of International Coal Trade - The Evolution of a Global Market, IEA/OECD 1997.19. See page II. 41 of Coal Information 1996, IEA Statistics, IEA/OECD 1997.


South Africa 32Latin America (Colombia and Venezuela) 18United States 15Poland 13Former Soviet Union 5Australia 5Indonesia 3China 1Other 8

Total 100


coal producers in OECD Europe cannot rely on higher world prices toimprove their competitiveness vis-à-vis coal imports. In summary, theoutlook for OECD Europe’s coal production remains weak and anyadditional volumes will be met by low-cost imports rather than high-cost domestic production. The share of the three largest suppliers islikely to increase, because restructuring in the Transition Economieswill reduce the amount of coal they have available for export. Inaddition, the transport costs from suppliers remote from Europe arehigh and are unlikely to be competitive in the European market.

Projections from Other OrganisationsTwo other major organisations produce European energy demand

projections: the European Union (EU) and the United StatesDepartment of Energy (USDOE). The last set of energy projectionsproduced by the EU was in 199620 and the Conventional Wisdom(scenario) is used here for comparison purposes. The USDOE’sreference case projection, published in 199821, is the other projectionconsidered in this chapter. Neither the EU22 nor the USDOE’s23

projections are exactly comparable with those of the World EnergyOutlook as their geographic coverage differs from that used in thisOutlook.

European Union Conventional Wisdom ProjectionApart from the differences in geographical composition between

the EU and OECD Europe, there are also differences in GDPassumptions. In order to normalise both projections (as far as possible)

20. Energy in Europe, European Energy to 2020 - A Scenario Approach, Directorate General forEnergy DGXVIII of the European Commission.21. International Energy Outlook 1998 - With Projections to 2020, April 1998 DOE/EIA.22. The European Union includes the following 15 Member countries - Austria, Belgium,Denmark, Finland, France, Germany, Greece, Ireland, Italy, Luxembourg, Netherlands, Portugal,Spain, Sweden and the United Kingdom. Thus the EU definition excludes the Czech Republic,Hungary, Iceland, Norway, Switzerland and Turkey which are included in the OECD Europedefinition adopted in this chapter.23. The USDOE projections cover Western Europe defined as the following 18 countries - Austria,Belgium, Denmark, Finland, France, Germany, Greece, Iceland, Ireland, Italy, Luxembourg,Netherlands, Norway, Portugal, Spain, Sweden, Turkey and the UK. This is basically the samedefinition as that used for OECD Europe in this chapter but with the Czech Republic andHungary omitted. In common with the definition used in this chapter, Poland is not included inthe USDOE’s Western Europe aggregation.

onto a comparable basis, the ratio of energy consumption to GDP isused in the following analysis. The energy ratio has then been put intoindex form (1995 = 100) to adjust for differences in geographicalcoverage.

Using the above approach, Figure 11.10 compares the EUConventional Wisdom (CW) scenario with the 1998 WEO’s businessas usual projection.

Figure 11.10: Total Primary Energy Supply/GDP Ratio

The important point to note is that the EU appears to beassuming a much greater decline in the ratio between energy andGDP. In the EU projections, the energy ratio declines at an annualaverage rate of 1.5% compared to 0.9% in the WEO projection. TheEU projections assume a somewhat higher oil price than in the WEOcase. The EU’s projection assumes that the oil price increases smoothlyfrom $17.60 in 1995 to $21/bbl in 2000, $29/bbl in 2010 and$31/bbl in 2020. In our projection, the oil price does not start toincrease until 2010 and then only reaches $25/bbl in 2015.Nevertheless, this price difference is too small to explain the differencein the decline in the energy ratio.

The difference between the EU and WEO projections is moremarked for transport. The two projections foresee very different pathsfor the mobility energy ratio. In our case, the mobility energy ratio


EU ONLY Total Primary Energy Supply / GDP EU CW

OECD Europe Total Primary Energy Supply / GDP IEA

1995 = 100140

120

100

80

60

40

20

0

1971 1980 1990 2000 2010 2020

continues to grow in line with past experience (see Figure 11.11). Inthe EU’s projections, the mobility energy ratio declines at an annualaverage rate of 1%. The higher oil price assumed in the EU projectionmay explain some of the difference, but it is clear that the EU’sprojections assume that other factors such as saturation, newtechnologies and changes in consumer behaviour result in a decliningenergy ratio in the transport sector. This assumption represents a clearbreak with past experience.

Figure 11.11: Transport Energy Demand/GDP Ratio

The comparison between the WEO and EU projections is equallymarked when the ratios of final electricity demand to GDP arecompared, as Figure 11.12 indicates.

The BAU case projects that this ratio will flatten out in line withpast experience. In the EU projection, however, the ratio of finalelectricity demand to GDP declines at an annual average rate of 0.9%,which is considerably different from that observed historically. As inthe transport sector, energy prices, assumptions about newtechnologies and changes in consumer behaviour appear to play asignificant role in the EU’s projections.

Outside the transport sector and total final demand for electricity,there is very little difference between the two projections, as Figure


EU ONLY Transport / GDP EU CW

OECD Europe Mobility (mainly oil used in Transport) / GDP IEA

1995 = 100120

100

80

60

40

20

0

1971 1980 1990 2000 2010 2020


11.13 indicates for the stationary sectors. Both projections show asimilar decline in the ratio of energy demand to GDP as in the past.

Figure 11.12: Electricity Demand/GDP Ratio

Figure 11.13: Stationary Sectors Energy Demand/GDP Ratio

EU ONLY Total Final Consumption excluding Transport & Electricity / GDP EU

OECD Europe Fossil fuel & heat in Stationary Uses / GDP

1995 = 100120

100

80

60

40

20

0

1971 1980 1990 2000 2010 2020

EU ONLY Total Final Consumption of Electricity / GDP EU CW

OECD Europe Electricity (final demand) / GDP IEA

1995 = 100120

100

80

60

40

20

0

1971 1980 1990 2000 2010 2020


Comparison of EU and IEA Electricity Generation ProjectionsThese projections are not directly comparable as previously

stated, because the EU projection only covers its 15 membercountries, whereas the Outlook’s projections are for OECD Europe,which has 21 member countries. Table 11.15 shows the compositionof the electricity generation mix in the two regions in 1995.

Table 11.15: Electricity Generation in OECD Europe andEuropean Union - 1995 (TWh)

As Table 11.15 indicates, electricity generation in 1995 in OECDEurope as a whole, was about 16% higher than in EU membercountries. Hydroelectricity makes up more than half the difference(non-EU countries with high reliance on hydro are Norway,Switzerland and Turkey). Over the projection period, total electricitygeneration in OECD Europe increases by 2.1% per annum, whereasin the EU scenario the growth is 1.3%. Fuel consumption in theperiod to 2020 increases at an annual rate of 1.3% in the IEA’sprojections. The corresponding growth rate in the EU projections is0.6%.

The following observations can be made on Table 11.16: • Coal use declines at rates lower than 1% in both projections.• Oil consumption is slightly higher in the IEA scenario.• Gas consumption increases faster in the IEA’s projection. This

is due to the fact that most of new generation comes fromgas-fired stations. Since the IEA projects higher electricitydemand, gas requirements are also higher.

• Nuclear power declines faster in the EU’s projections. In ourprojections, there is additional new nuclear capacity in OECDEurope, outside EU countries.

OECD Europe Per cent E U Per cent

Total generation 2678 100% 2308 100%Solid Fuels 828 31% 742 32%Oil 237 9% 225 10%Gas 255 10% 233 10%Nuclear 861 32% 810 35%Hydro 486 18% 287 12%Other Renewables 10 0% 10 0%


• Hydro power increases faster in the IEA projections; most ofthis increase is expected to take place in OECD countriesoutside the EU.

• The IEA estimates on combustible renewables and waste aremore conservative than those of the EU.

• Other renewable energies (solar, wind, geothermal) grow fasterin the IEA’s projections.

Table 11.16: Comparison of Power Generation Projections 1995 - 2020

Figure 11.14: Electricity Generation Figure 11.15: Fuel Use in Power Stations(1995 = 100) (1995 = 100)

Figure 11.14 plots electricity generation against GDP for the twodifferent projections. Figure 11.15 shows fuel consumption againstGDP. In both charts, GDP and energy have been indexed to 1995.The gap between the two sets of projections is somewhat narrower in

Elec

trici

ty G

ener

atio

n

Fuel

Con

sum

ptio

n

200

180

160

140

120

100

200

180

160

140

120

100

GDP GDP

IEA

EU

IEA

EU

100 120 140 160 180 100 120 140 160 180

IEA % per annum EU % per annum1995-2020 1995-2020

Total Generation 1.3 0.6Coal only -0.7 -0.3Oil -0.1 -2.4Gas 7.3 4.8Nuclear -0.7 -1.5Hydro 1.0 0.7Waste 2.3 7.0Other Renewables 9.2 6.4


Figure 11.15. This implies that the IEA fuel mix is slightly moreefficient. Indeed, average fossil fuel efficiency in the IEA’s projectionsincreases from 36% in 1995 to 47% in 2020. In the EU projections,efficiency increases from 38% to 45%. The difference can beattributed to higher demand for gas in the IEA projections; this gas isburned mostly in combined cycle gas turbine plants that are moreefficient than the conventional steam technologies, currently in use.

Finally, the IEA’s total electricity generation is more efficientbecause of the higher percentage of hydro in OECD Europe’s fuel mix(the conversion efficiency for hydroelectricity is assumed to be 100%).

United States Department of Energy’s Reference Case ProjectionThe USDOE’s 1998 International Energy Outlook contains

somewhat less detail than the EU’s 1996 publication, but it stillprovides a useful benchmark against which to compare our projectionsfor OECD Europe. Table 11.17 compares the projected growth inTPES during the period 1995 - 2020.

Table 11.17: WEO 1998 BAU versus IEO 1998 Reference Case

Note: USDOE projection refers to Western Europe whereas IEA projection refers to OECDEurope.

Both organisations project TPES to grow at a similar rate of 1.1%- 1.2%, considerably higher than the EU’s 0.7%. Both the USDOEand the EU have lower projections than the IEA for oil and nuclearpower. An interesting feature of the USDOE projection is the highprojected growth rate in gas demand of 3.8%. This is, in part, becausegas replaces oil in heat production. The USDOE also projects thattotal final electricity demand will grow at an annual average rate of2.4%, slightly faster than projected by the IEA for OECD Europe butmore than a percentage point greater than projected by the EU.

Annual Growth Rates 1995-2020 USDOE 1998 IEO IEA WEO 1998

Total Primary Energy Supply 1.2% 1.1%Solid Fuels -0.1% -0.3%Oil 0.3% 1.1%Gas 3.8% 3.0%Nuclear -1.2% -0.7%Hydro / Other 2.1% 1.6%


Table 11.18: Average Annual Growth Rate in Total Final ElectricityDemand 1995 - 2020

With the USDOE projecting that TPES will grow at 1.2% andassuming that GDP growth will average 2.4% during the period 1995to 2020, the TPES energy ratio (TPES / GDP) is projected to declineat an annual average rate of 1.2%. This decline is somewhat faster than0.9% projected here for OECD Europe. The higher GDP growth rateassumed in the USDOE projections may explain why the USDOE’sgas and electricity demands grow faster than in the 1998 WEO.Higher economic growth would lead to a more rapid turnover of thecapital stock and thereby increase the potential for gas and electricityto substitute for coal and oil. The decline in the USDOE projectedenergy ratio is very similar to that observed during the last quarter ofa century and consistent with our own projection.

The oil price assumptions made by the IEA (BAU), USDOE(reference case) and EU (CW) are shown below.

Table 11.19: Oil Price Assumptions Real $ per Barrel

Note: The oil prices in the above table are in the following units: WEO real 1990$, USDOE real1996$ and EU real 1993$.

The USDOE and WEO oil price assumptions are broadly similar,although the EU’s oil price assumption for 2020 is somewhat higherthan in either of the other studies. Some additional incentive to reduceenergy demand may therefore exist in the EU’s projections whencompared to the USDOE and IEA’s projections.

USDOE 1998 IEO IEA WEO 1998 BAU EU 1996 CW

2.4% 2.1% 1.3%

1995 2000 2010 2020

WEO 1998 BAU $15 $17 $17 $25USDOE 1998 IEO - $19 $20 $22EU 1996 CW $17.6 $21 $29 $31


Chapter 12: OECD North America 203

CHAPTER 12OECD NORTH AMERICA

IntroductionOECD North America1 (the United States and Canada) is a

homogenous region in terms of energy and economic structure. In1996, it accounted for more than a quarter of world primary energydemand and around half of OECD demand. At the same time, theregion has large hydrocarbon and hydropower resources. The US is thelargest oil-consuming and oil-importing country in the world and isthe second largest producer of oil after Saudi Arabia2.

Compared to other OECD countries, the US and Canada havehigh ratios of energy use to GDP. Many factors combine to producethis effect. Among the most important are low energy prices, highincomes per head, large distances between centres of population andextreme climate conditions in both winter and summer.

Figure 12.1: Energy Intensities of Selected OECD Countries

1. Although Mexico joined the OECD in 1994, it has been considered together with the LatinAmerican region for projection purposes.2. When natural gas liquids and alcohols are included.

0.0 0.1 0.2 0.3 0.4

Total Primary Energy Supply/GDP (toe per $ thousand in 1990 prices and PPP)

CanadaUnited States

BelgiumAustralia

NetherlandsGermany

FranceNorway

United KingdomDenmark

JapanSpain

Italy


Table 12.1 provides a comparison of gasoline prices in differentOECD countries. In absolute terms, European gasoline taxes in 1996were some 8 times higher than those in the US. The low level of taxeson transportation fuels in the US, make that country’s oil demandparticularly sensitive to changes in world crude oil prices.

Table 12.1: Retail Gasoline Prices and Taxes 1997 (US cents per litre)

Source: Energy Prices and Taxes 1998, IEA

The United States is the largest economy in the world, with aGDP of about $6.3 trillion (at 1990 prices and PPP) in 1996,accounting for about 37% of total OECD and more than one-fifth ofworld GDP. Canada had a GDP of $600 billion in 1996 andaccounts for about 3.3% of the OECD’s total GDP. Following arecession in the early 1990s, the economies of the US and Canadahave recovered with economic growth rates for both countries in1997 close to 4%. For the US, this growth was a nine-year high, theunemployment rate was at its lowest level for a generation andinflation down to rates last seen in the mid-1960s. This is the thirdlongest expansion period since the Second World War. The Canadianeconomy, which is closely linked to that of the US, has also continuedto grow at a healthy pace.

Our business as usual assumptions suggest a soft landing for theUS economy with growth easing back and inflation staying undercontrol. GDP in OECD North America is expected to grow at anaverage annual rate of 2.1% between 1995 and 2020, a slowdowncompared to the annual average growth rate of 2.7% in the period1971 to 1995. Continued immigration and an increasing birth ratecontribute to a growth in population of slightly below 1% perannum. In consequence, per capita incomes are expected to increaseby 1.3% a year to 2020, a lower rate than has been experienced overthe last two decades.

Retail Price Tax Tax (%)

US 37.4 10.1 27Canada 43.5 20.8 48Japan 96.0 53.6 56France 120.7 94.6 78Germany 111.0 79.6 72Italy 118.5 85.4 72


Table 12.2 lists the principal economic and demographicassumptions made for OECD North America in the BAU projection.These assumptions are discussed in Chapter 2. The most significantfeature is a rise in gas prices from $1.7 per thousand cubic feet in2005 to $3.5 in 2015, reflecting some tightness in the NorthAmerican gas market and increasing use of unconventional gassupplies. These issues are discussed later in this chapter and inChapter 8.

Table 12.2: OECD North America Assumptions

Throughout the United States, restructuring is taking placetoward more competitive electricity and gas markets. The outcome ofthese market reforms poses additional uncertainties for the projectionspresented in this Outlook.

Box 12.1: Energy Market Reforms in US

Restructuring of the electricity sector in the US is expected tohave a major impact on electricity consumption trends. The bulkmarket was opened to further competition by the Federal EnergyRegulatory Commission (FERC) in April 1996. FERC has notopted for the most radical approach to liberalisation: full verticalseparation of transmission from generation and supply. Rather, ithas chosen a set of grid access rules with control of day-to-dayoperations of the transmission grid to be transferred to newly-

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal Price ($1990 per metric ton) 44 40 42 46 0.5%Oil Price ($1990 per barrel) 6 15 17 25 2.1%Natural Gas ($1990 per 0.6 1.3 2.6 3.5 3.9%1000 cubic feet)GDP ($ Billion 1990 and PPP) 3580 6710 9432 11175 2.1%Population (millions) 230 293 331 357 0.8%GDP per Capita ($ 1000 1990 and 16 23 29 31 1.3%PPP per person)


created institutions called Independent System Operators. It isgenerally believed that within the next three to five years, at leasthalf of the US citizens will obtain the right to choose theirelectricity supplier. Estimates of the results of competition in themarket for electric power vary widely. The US governmentprojects price decreases of some 10% in the short term, and anadditional 11% by the year 20153.

Further liberalisation of the US natural gas market is unlikelyto have a major impact on overall energy consumption, as themarket is already largely deregulated4. FERC liberalised bulktransactions at the federal level in 1992. At present, about half ofall final gas sales are made by suppliers other than the localdistribution company. More importantly, it is estimated that largeindustrial customers and power plants can already switch suppliersin some 75% of all cases. The remainder of the gas market is notseen as attractive to gas suppliers, as it mainly consists of smallcustomers with low load factors; they mainly consume gas duringthe heating season, and are thus expensive to serve. Further marketopening in the gas sector may not lead to large increases in gasdemand5.

Energy Demand Outlook

OverviewIn OECD North America, primary energy demand is expected to

grow by 0.8 per cent per annum over the projection period. Thisincrease is low by historical standards and lower than the projectedOECD average of 1% per annum. In addition to GDP and theevolution of oil and gas prices, other important factors contributing tothe slowing of energy demand growth include the saturation of

3. Electricity Prices in a Competitive Environment: Marginal Cost Pricing of Generation Services andFinancial Status of Electric Utilities: A Preliminary Analysis through 2015, Department of Energy(DOE)/Energy Information Administration (EIA), Washington, DC, August 1997.4. Natural Gas Pricing in a Competitive Market, IEA/OECD, (forthcoming).5. Energy Policies of IEA Countries - United States 1998 Review, IEA/OECD, 1998 and EnergyPolicies of IEA Countries - Canada 1996 Review, IEA/OECD, 1996.


markets for domestic appliances, already high vehicle ownership levelsand expected improvements in energy efficiency, especially in thepower generation sector.


In terms of total primary energy demand, consumption of solidfuels is expected to grow rapidly. This is mainly due to changes in thefuel mix of the power generation sector as a result of rising gas and oilprices. The fall in the use of nuclear power in electricity generationwill be largely taken up by coal. Consumption of oil and gas areexpected to grow rather slowly at 0.7% and 0.6% per annum onaverage. As a result, the market shares of oil and gas in total primaryenergy demand are expected to decline slightly, and solids are expectedto increase their market share by over 7 percentage points over theoutlook period. As shown in Figure 12.2, the share of nuclear isprojected to fall by about 5 percentage points in 2020, compared tothe current level.

As Table 12.4 shows, total final energy consumption (TFC) isexpected to grow at an annual rate of 0.7%. Electricity is the maindriver of final energy demand. It is projected to grow at a rate slightlyhigher than that of GDP. The current 19% share of electricity in totalfinal energy consumption is expected to reach 25% by 2020. Final oiland solids demands are expected to increase at a similar pace to that ofaggregate final demand and gas demand is projected to decline after2010 due to an increase in gas prices. Heat demand grows the fastest,from a low base in 1995.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TPES 1724 2312 2724 2846 0.8%Solid Fuels 338 582 737 927 1.9%Oil 789 873 1025 1050 0.7%Gas 548 576 705 676 0.6%Nuclear 12 212 182 114 -2.4%Hydro 37 56 58 60 0.3%Other Renewables 1 13 18 18 1.4%


Figure 12.2: Total Primary Energy Supply, OECD North America


Stationary SectorsAs shown in Table 12.5, consumption in stationary uses of fossil

fuels is projected to increase slightly till 2010 and to decline thereafter.Key influences on the energy outlook of the residential andcommercial sectors will be increases in personal incomes, movementsin energy prices, demographic trends, appliance penetration andefficiency trends in the energy-using equipment in these sectors.Annual population growth of 0.8% for the projection period, againstthe last two decades’ average of 1.1%, is a contributing factor to

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TFC 1289 1581 1836 1891 0.7%Solid Fuels 100 76 80 87 0.6%Oil 709 819 958 978 0.7%Gas 339 379 385 346 -0.4%Electricity 140 300 402 464 1.8%Heat 0 8 12 16 3.0%

Solid Fuels25%

Other Renewables1%

Hydro 2%

Nuclear9%

Gas25%

Oil38%

Solid Fuels33%

OtherRenewables

1%Hydro 2%

Nuclear4%

Gas24%

Oil37%

1995 2020

2312 Mtoe 2846 Mtoe


slowing energy demand in the residential sector. Markets for manymajor appliances (space heaters, water heaters) in the US and Canadaare already tending to saturate. It is also expected that the averageefficiency of the stock of appliances will increase, mainly as a result oftechnological innovation and stock turnover. In the commercial sector,saturation trends will contribute to the declining pace of energydemand growth. Lower growth in industrial output, in line with theassumptions made for GDP growth, is the underlying factor for thedecreasing trend of industrial energy demand. The increasingpredominance of less energy-intensive industries is a furthercontributing factor.

Figure 12.3: Stationary Uses by Fuel

Table 12.5: Energy Consumption in Stationary Sectors (Mtoe)

Solid Fuels Oil Gas Heat

400

350

300

250

200

150

100

50

0

mill

ion

tonn

es o

il eq

uiva

lent

Gross Domestic Product ($ Billion at 1990 prices and Purchasing Power Parities)

3000 4000 5000 6000 7000 8000 9000 10000 11000 12000

1971-1995 1996-2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 739 688 695 650 -0.2%Solid Fuels 100 76 80 87 0.6%Oil 317 247 249 239 -0.1%Gas 322 358 354 308 -0.6%Heat 0 8 12 16 3.0%

MobilityEnergy demand for mobility in OECD North America is

projected to increase broadly in line with GDP to the year 2010. Itbegins to slow thereafter due to an assumed rise in the world oil price.Total energy demand for mobility is expected to grow by 1.5% perannum between 1995 and 2010 and 1.1% for the whole projectionperiod. This compares with the 1.6% growth rate of the last twodecades. The OECD North American region has the highest level ofcar ownership of all OECD regions. This is expected to approachsaturation.

Figure 12.4: Mobility

Table 12.6: Fossil Fuel Use for Mobility (Mtoe)

Figure 12.4 shows sharp declines in energy use for mobility afterthe oil price shocks and the resulting government action to improve


3000 4000 5000 6000 7000 8000 9000 10000 11000 12000


800

750

700

650

600

550

500

450

400

350

300

mill

ion

tonn

es o

il eq

uiva

lent

1971-1995

1996-2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 409 593 739 777 1.1%


energy efficiency, especially the Corporate Automobile Fuel Efficiency(CAFE) standards. The evolution of transportation fuel efficiency overthe projection period is an important source of uncertainty for theprojections presented here. Similarly, the future of alternative-fuelvehicles, following legislative mandates at the Federal and State level inthe US, may well alter future trends of mobility energy use.

Oil is the predominant transport fuel, accounting forapproximately two-thirds of total primary oil consumption in OECDNorth America and 17% of total world oil consumption. As shown inFigure 12.5, oil for mobility accounted for all the growth in oildemand between 1971 and 1995 and is expected to do so again overthe outlook period.

Figure 12.5: Incremental Changes in Oil Consumption

ElectricityFigure 12.6 shows OECD North America electricity demand

rising regularly along with increasing income. This continues theestablished past trend. The income elasticity shows a correspondingslowly declining trend. It was close to 2 in the 1960s and declined toabout 1.2 in the last two decades. It is projected to decrease to 1 over

Mobility Stationary Uses Inputs to Power Generation

mill

ion

tonn

es o

il eq

uiva

lent

200

150

100

50

0

-50

-1001971-1995 1995-2020


the outlook period. The underlying factors expected to contribute tothis trend include market saturation of electrical appliances andimprovements in appliance efficiency.

A major uncertainty affecting the electricity demand projectionsis the expected impact of market reforms. As discussed in Box 12.1,price reductions due to increasing competition in the energy sectorcould lead to additional electricity demand. On the other hand, newair-quality standards prepared by the US Environmental ProtectionAgency may cause significant increases in the generating costs ofpower that could lead to upward pressure on retail electricity pricesand reduce electricity demand. However, the sharp increases in pricesat the time of the oil shocks did not lead to a major change inelectricity demand on a short-term basis, so a rapid deviation from theBAU trend should not be expected.

Figure 12.6: Electricity Demand

Table 12.7: Total Final Electricity Demand (Mtoe)

Gross Domestic Product ($ Billion at 1990 prices and purchasing Power Parities)

3000 4000 5000 6000 7000 8000 9000 10000 11000 12000

mill

ion

tonn

es o

il eq

uiva

lent

500

450

400

350

300

250

200

150

100

50

0

1971-1995

1996-2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 140 300 402 464 1.8%


Supply

Power GenerationIn the BAU projection, electricity generation in North America

increases at an average rate of 1.8% per annum. This may becompared with a growth rate of 3.2% per annum experienced since1971. By 2020, annual generation could represent 6363 TWh, a 55%increase above current levels. Coal and gas are expected to be the keyfuels in the projected electricity mix. Gas-fired generation appears tobe the most economic option for new plant, particularly in the firsthalf of the outlook. In the second half, higher gas prices, associatedwith higher gas production costs, could switch the economics ofpower generation in favour of coal. Consequently, although the shareof natural gas generation increases from 13% in 1995 to 24% of totalin 2020, coal will continue to supply the bulk of electricity in theregion. The role of oil is expected to remain marginal, as oil-firedplants will continue to be called at times of peak load. Nuclearelectricity decreases, as no new nuclear plants are built and nuclearplant retirements accelerate in the second half of the outlook period.Hydropower shows a small increase. Other renewables increaseslightly, as their costs remain high.

Figure 12.7: North American Electricity Output

7000

6000

5000

4000

3000

2000

1000

01971 1980 1995 2010 2020

Oil

Gas

Solid Fuels

Nuclear

Hydro Other Renewables

TWh


Table 12.8: Electricity Generating Capacity by Fuel (GW)

Most of the region’s net increase in capacity is expected to comefrom natural gas fired plants in the form of combined cycle gasturbines (CCGTs), where medium- to base-load capacity is required,and simple cycle combustion turbines (which can use either gas or oildistillates depending on their cost competitiveness) where new orreplacement peaking capacity is needed. Natural gas fired capacity hasincreased significantly over the past few years and is expected to go ondoing so while gas prices remain low. The following table showsplanned capacity additions for US utilities for the period 1996 to2005; around two thirds of this capacity is gas-fired.

Table 12.9: Planned Capacity Additions in US Electric Utilities, 1996 to 2005

Source: Inventory of Power Plants in the United States, 1997, US EIA/DOE, Washington DC,1998.

1995 2010 2020

Solid Fuels 372 418 564of which CRW 12 15 16Oil 45 51 58Gas 209 415 450Nuclear 116 96 59Hydro 165 172 177of which Pumped Storage 22 22 22Other Renewables 5 7 10Total 912 1159 1317

Capacity (MW) % of Total

Coal 4845 12Oil 5951 15Gas 27371 68Hydro 431 1Nuclear 1170 3Other 383 1Total 40151 100


A number of factors have changed the relative advantages ofpower generation technologies to favour gas-fired turbines in simple orcombined cycle configuration. Lower gas prices since the mid-1980shave made gas attractive for medium and, in some cases, baseloadapplications. The removal of most of the restrictions of the PowerPlant and Industrial Fuel Use Act (PIFUA) in the US in 1990eliminated an important barrier to increased use of gas by utilities.Combustion turbines are now more efficient and more reliable thanthey were a few years ago and their capital costs have fallen. The newgeneration of CCGT plants is approaching 60% efficiency.Environmental restrictions favour gas, as it is free of sulphur and emitsless carbon dioxide and other pollutants when combusted than otherfossil fuels. For example, the New Source Performance Standards(NSPS) impose capital-intensive technological control on new coalplants. Natural gas consumption in power stations is projected todouble by 2020 and to account for more than 40% of NorthAmerican gas demand.

Figure 12.8: Comparison of the Generating Costs of New Steam Coaland CCGT Plants, 2000

Coal-fired generation is projected to increase by 2.3% perannum. By 2020, coal-fired plants could supply more than half of the

Operating Costs (incl. fuel) Cost of Capital

cent

s pe

r kW

h

3.0

2.5

2.0

1.5

1.0

0.5

0.0Coal Gas


region’s electricity. Coal-fired capacity increases at a lower rate of 1.7%per annum. This means that coal capacity is used more intensively inbaseload, particularly when nuclear units serving baseload duty areretired. Figure 12.8 compares the costs of new coal and CCGT plantsin the year 2000. Overall, CCGT plants are more economic to build,but coal plants have lower running costs and therefore, once they arebuilt, are more economic for baseload use. Higher use of the existingstock could also result from the restructuring of the electricity industrythat is currently taking place in the US.

Oil use in power generation in North America is the lowest in theOECD. It currently accounts for 2% of total generation and isprojected to maintain this share throughout the projection period. Inabsolute terms, it shows a modest increase, from 98 TWh in 1995 to151 TWh by the end of the outlook period.

There are no plans to build new nuclear power plants in the USor Canada in the foreseeable future; unfavourable economicscombined with siting and permit problems lead to a significant declineof nuclear power. The last unit to be commissioned in the region wasWatts Bar 1 in Spring City, Tennesee, in 1996. It is a 1170 MWpressurised water reactor that will supply enough electricity for 200 000Tennesse Valley households. Nuclear capacity in the region in 1995was 116 GW. By 2020, some 58 GW of nuclear plants could beretired, bringing nuclear capacity down to 59 GW.

Table 12.10: Canadian Nuclear Plants Temporarily Shut Down

Canadian nuclear capacity stood at 16.4 GW at the beginning of1995, representing 14% of the country’s installed capacity. At the endof this year, unit 1 at Bruce Power Station was shut down after twentyyears of operation. No nuclear units have been commisioned in thecountry since 1993. In August 1997, Ontario hydro decided

Unit Name Unit Size (MW) Commercial Operation

Pickering 1 542 1971Pickering 2 542 1971Pickering 3 542 1972Pickering 4 542 1973Bruce 1 904 1977Bruce 2 904 1978Bruce 3 904 1979


temporarily to shut down 7 of its 19 nuclear units in order to refurbishthem and extend their lives to 40 years. The 7 units are scheduled tobe brought back into operation before 2010 and this has been takeninto account in the BAU projection. There is, however, someuncertainty as to whether this will happen.

Recently, two nuclear power plants in the United States appliedfor extension of their licences. Similar applications for other plantsmay follow. For several years, nuclear plants had very low runningcosts, but they have risen since the mid-1980s. Fossil fuel prices havefallen since 1986, so that by 1996 the average production cost offossil-fuelled steam plants was only 3% higher than that of nuclearplants, as shown in Table 12.11. There would have to be significantincreases in fossil fuel prices for new nuclear plants to becomecompetitive again, based on a comparison of full generating costs.

Table 12.11: Average Power Production Expenses for US Nuclearand Fossil-fuelled Steam Plants (cents per kWh), 1996

Source: Financial Statistics of Major US Investor-Owned Electric Utilities 1996, Washington, DC,1997.

Hydroelectric capacity in Canada is assumed to increase by about12 GW in the period 1995 to 2020. Most of the increase will comefrom new plants in Quebec. The 828 MW Sainte Marguerite plant isexpected to come on line in 2001. Five more power stations, Eastmain1, Mercier, Kipawa, Haut Saint Maurice and Ashuapmushan, totalling2015 MW, are expected to be developed during the outlook period.The largest new hydro project is Grande Baleine, in the same province,but only part of it is expected to be completed before 2020. Other newCanadian hydro projects include the Wukswatim and Notigi stations(405 MW) in Manitoba6. In the United States, only small capacityincreases are expected, primarily because of lack of new sites, highconstruction costs, environmental considerations and competing usesfor water resources.

The BAU projection of renewable energy for electricity

Fuel Operation Maintenance Total

Fossil Fuel 1.65 0.23 0.25 2.13Nuclear 0.55 0.95 0.57 2.10

6. Canada’s Energy Outlook 1996-2020, Natural Resources Canada, 1997.


generation is based partly on national forecasts (USDOE and NaturalResources Canada) and partly on internal IEA sources and estimates.In both countries, most incremental generation from renewables isexpected to come from biomass and waste. Other sources, such aswind and solar power, show only small increases. Electricity generationfrom renewable energies is costly compared with conventional fossilfuel technologies. Increased use of these sources could be expectedonly if encouraged by specific supportive strategies. For example, inthe United States, a very popular approach is the renewable portfoliostandard (RPS), which specifies a certain percentage of electricity thatmust be supplied by renewable energies. Canada’s strategy to stimulaterenewable electricity generation is outlined in its Renewable EnergyStrategy.

OilThe following table summarises OECD North America’s oil

balance until 2020. Details on how the oil balance was obtained canbe found in Chapter 7.

Table 12.12: OECD North America’s Oil Balance (Mbd)

North America’s position as the world’s most mature oilproducing region means that oil reserve constraints are likely tocontinue to be a major determinant of the region’s oil production.During the projection period, some increase in production will comefrom offshore7 oilfields, particularly in the Gulf of Mexico. Prospectsfor growth in onshore oil production are less optimistic, although thedevelopment of new technologies may lower the rate of decline insome fields.

Given these reserve constraints, the long-term outlook is one ofsteadily rising net oil imports. Towards the end of the projectionperiod, rising unconventional oil production in Canada could reduce

1996 2010 2020


7. The prospects for offshore oil production have been examined in a recent IEA publication,Global Offshore Oil Prospects to 2000, IEA/OECD Paris, 1996.


the region’s reliance on oil imports. Since it is uncertain how futureunconventional oil production will be split between Canada andVenezuela, where the two largest deposits of unconventional oil aresituated, the above oil balance table includes only thoseunconventional oil projects for which production plans are at anadvanced stage of preparation, or are already in production.

GasProspects for gas supply in North America are discussed in detail

in Chapter 8. The estimates for gas reserves quoted there aresubstantial for both the United States and Canada, especially ifunconventional gas sources (coal bed methane and tight reservoir gas)are included. Indeed, unconventional gas has played a significant rolesince 1990, accounting for almost all the growth in US gasproduction8. The main uncertainties are the level of ultimaterecoverable gas reserves in the region in relation to the size ofcumulative gas production by 2020, the cost of incremental gassupplies and the balance among gas demand, supply and price in theNorth American market.

Official forecasts for the United States and Canada take the viewthat gas reserve estimates are likely to increase further and thatindigenous gas supply will be sufficient to meet growing gas demandto 2020 at a price less than $3 per thousand cubic feet (tcf ). This viewis shared by major gas suppliers in the region, at least up till 2015.

As Chapter 8 indicates, current estimates of North American gasreserves differ, and projections of the US gas supply-demand balanceto 2020 indicate some tightness in supply towards the end of theperiod. Considerable uncertainty exists on gas production costs, oncethe lowest-cost sources are used up. For these reasons, we adopt a lessoptimistic view. In the BAU projection, the gas price is assumed todouble (at 1990 prices) from $1.7 per tcf in 2005 to $3.5 in 2015 andthen to remain at that level to 2020. Most other projections expectthe gas price to remain below $3 per tcf.

We assume that a price level of $3.5 is not likely to attract bulkimports of LNG into North America, and indigenous supply anddemand are expected to balance to 2020. The gas price rise will restrictgas demand growth, however. We do not doubt the importance of

8. The World’s Non-Conventional Oil and Gas, Hydro-carbons of last recourse, A. Perrondon, J.H.Laherrère and C.J. Campbell, Petroleum Economist, March 1998.


technological developments in gas exploration, development andproduction, nor the enterprise and innovation of gas companies.However, we feel that the assumption that gas production in NorthAmerica can continue to grow at low production costs till 2020requires further analysis. Until that analysis is completed, we prefer amore cautious approach.

The following table shows how OECD North America’s gasbalance is projected to develop over the projection period. Chapter 8provides a discussion on how this supply projection was obtained.

Table 12.13: OECD North America’s Gas Balance (Mtoe)

CoalThe US is the world’s second largest producer of coal, after

China. In 1996, its coal production reached 878 million tonnes (Mt),about 24% of world coal supply. The US has vast coal resources,estimated at around 650 000 Mt. More than half of US electricitygeneration is supplied from coal, and about 85% of coal production issold to domestic utilities. It is expected that power generation willaccount for an increasing share of US coal production as other fuelsare substituted for coal in other energy-consuming sectors.

The share of the US in the internationally-traded coal market fellsignificantly, from about 50% in 1970 to about 17% in 1995. USproducers effectively set the upper limit to world prices by theircapacity to enter the market whenever the price is high and exploittheir excess capacity. US coal producers make decisions on investmentin new capacity according to their expectations of future coal demandfrom the domestic market. US fields are closing faster than they arebeing replaced, because of low returns on investment. Althoughdomestic prices have fallen, they are currently above export prices. Inthis situation, where exports are marginal, production costs arecovered by domestic sales. Otherwise, it is unlikely that the situationcould be sustained; either prices will rise or less export coal will beavailable, particularly for low and medium volatility metallurgical coal

1995 2010 2020

Demand 602 756 762Supply 592 759 764Net Imports -2 -2 -2


and low-sulphur steam coal. Supply can be expected to continue totighten for better quality coal, leaving higher-sulphur coal for export.

Figure 12.9: Hard Coal Production and Exports

Because of their high level of dependence on the electricity sector,restrictions on emissions under the Clean Air Act, and deregulationand restructuring in the electricity sector, could have a significantimpact on US coal producers. In general, the changes in the USdomestic market are pushing coal producers to investment in low-sulphur coal for the domestic market, leaving surpluses of highersulphur coal for export in the medium term, but creating uncertaintyas to the level and grades of coal available for export in the longerterm.

Canada supplies about 1% of the world’s hard coal productionand 4% of the world’s brown coal production. In 1996, Canadaproduced about 40 Mt of coal and exported more than three quartersof this amount, primarily to Japan, Republic of Korea, Chinese Taipeiand Brazil.

Comparison of Projections with Other OrganisationsThis section compares the projections of the US Department of

Energy with the BAU projections presented here. As shown in Table12.14, assumptions for GDP growth rates, the main driver of energydemand, are the same. For future world oil price developments, bothof the organisations assume increases, albeit at different paces and

1000000

800000

600000

400000

200000

0

Thou

sand

Ton

nes

Production Exports

1960 1965 1970 1975 1980 1985 1990 1996


different times. The main difference between USDOE and WEO 98assumptions lies in the evolution of gas prices. Because of assumedrising North American gas production costs, the BAU projectionassumes significantly higher natural gas prices than is assumed in theUSDOE’s projection.

Table 12.14: Comparison of Key Assumptions for the USDOEand the BAU Projections

Over the period 1995-2020, the USDOE reference caseprojections9 for the US foresee a higher pace of energy demandgrowth than does the BAU projection. As shown in Table 12.15,USDOE projects an average growth of primary energy demand of1.2% per annum against 0.8% for this Outlook. This difference canbe largely attributed to the assumed increase in oil price over theperiod 2010 to 2015, and of the gas price from 2005 to 2015, in theIEA projections. Figure 12.10 compares the OECD North Americaoil and natural gas price assumptions of the two models over theprojection period.

Table 12.15: Comparisons of Growth Rates of Total Primary Energy Supplyfor the USDOE and the BAU Projections

USDOE WEO 98

1995-2010 1995-2020 1995-2010 1995-2020

GDP Growth Rates 2.3% 1.9% 2.3% 2.1%Population Grawth Rates 0.8% 0.8% 0.8% 0.8%

Average Annual USDOE WEO 98Growth Rates 1995-2020 1995-2020

TPES 1.1% 0.8%Solid Fuels 1.0% 1.9%Oil 1.3% 0.7%Gas 1.6% 0.7%Nuclear -2.2% -2.4%Hydro 0.1% 0.3%Other Renewables 1.7% 1.4%

9. Annual Energy Outlook 1998 - With Projections through 2020, December 1997, USDOE/EIA.


Figure 12.10: Comparison of the Price Assumptions for the USDOEand the IEA Projections

In the IEA projection, the higher energy price environment leadsto a slowdown in energy demand, in particular that of oil and gas.This region is very responsive to energy prices, and the greatersensitivity of energy demand to higher prices in OECD NorthAmerica compared with other OECD regions has been reported inseveral studies10. For the period 1995 to 2010, our projectionconfirms this finding: total primary energy demand is expected togrow 1.1% per annum in the BAU projection which is similar to thatof USDOE.

As a result of the above differences in projected energy demandpatterns over the period 1995-2020, the projected energy intensityimprovement rates of the two models diverge significantly. Whereasthe USDOE expects a decline in energy intensity of 0.8% per annumon average, the WEO 98 BAU case projects a decline of 1.2%annually.

The two projections also differ in respect to growth in finalelectricity demand. The IEA projection has higher demand forelectricity; 1.8% per annum compared with 1.4% per annum forUSDOE. The slower pace of electricity demand growth in theUSDOE projections is explained by the factors “saturation, utilityinvestments in demand-side management programmes and legislationestablishing more stringent equipment efficiency standards”11.

10. See, for example, The Costs of Cutting Emissions: Results from Global Models, OECD, 1993,amongst others.11. See page 50 of Annual Energy Outlook 1998-With Projections Through 2020, December 1997,DOE/EIA, for a detailed discussion.

Oil Prices Gas Prices160

140

120

100

80

60

40

20

0

200

150

100

50

0

1997

WEO 98

DOE

WEO 98

DOE

2010

2020

1997

2010

2020


The differences with OECD North America oil demandprojections are mainly due to expected developments in thetransportation sector. While USDOE projects a growth rate of 1.6%per annum, the BAU projection has an annual increase of 1.1% in theperiod of 1995-2020. This can be mainly attributed to the oil priceincrease in the period 2010-2015.

For power generation, the assumed increases in the gas price leadsto less use of gas and consequently more coal in the BAU projection.This is reflected in the higher growth rate of solids in total primaryenergy demand in Table 12.15. The BAU projection has similarnuclear capacity figures but a somewhat higher estimate of windpower in 2020.


Chapter 13 - OECD Pacific 227

CHAPTER 13OECD PACIFIC

IntroductionThe OECD Pacific region1 is diverse in terms of both its energy

and economic structures. Japan, the OECD’s second largest energyconsumer, is the dominant energy user in the region with totalprimary energy demand of 510 Mtoe in 1996. This is more than 80%of the region’s total consumption. Australia is a major producer of coaland New Zealand has a large supply of hydropower.

In 1996, the region accounted for 14% of total OECDcommercial primary energy demand, compared with 10% in 1971.This increasing share results partly from relatively high economicgrowth in the region over the last 25 years (3.5% per annumcompared with 2.7% for the total OECD).

Compared to most OECD economies, Japan has a low energyintensity level, 0.2 toe per $1000 in 1990 prices and purchasing powerparity (PPP) terms. This is some 30% less than that of the OECD,and is partly due to the country’s limited energy resources andtraditionally high energy prices. Australia and New Zealand havehigher energy intensities than Japan, around 0.3 toe per $1000 (at1990 prices and PPP). End use prices in Japan are significantly higherthan in the United States and are comparable to those in someEuropean countries. High energy costs and high tax rates are the mainreasons for this. Taxes account for more than half of the total price ofautomotive fuels both in Japan and Australia. Gasoline prices in Japanare almost twice as high as in Australia and about three times as highas in the United States. Industrial energy prices in Japan havehistorically been subject to very low taxes in comparison with otherOECD countries.

Box 13.1 discusses the possible impact on end-user prices ofplanned deregulation and institutional reform in the Japanese energysector. The uncertain outcome of these reforms contributes to theoverall uncertainty of the projections in this study.

1. The region consists of Japan, Australia and New Zealand. Although the Republic of Korea joinedthe OECD in 1996, it has been included with other East Asian countries for modelling purposes.


The OECD Pacific region is diverse in terms of economicstructure. The manufacturing sector accounts for 24% of GDP inJapan, compared with 15% and 18% in Australia and New Zealand.The high share of manufacturing in Japan is reflected in the 40%industrial share in total final energy consumption, significantly higherthan the OECD average of about 30%.

In the business as usual case, GDP in the OECD Pacific region isassumed to increase at an average annual rate of 1.8% over the outlookperiod, a slowdown compared to the 3.2% achieved between 1971and 1995. The recent Asian financial crisis is assumed to contribute tothe future slowdown in economic growth. The OECD Pacific region’strade and other economic linkages with the industrialising Asiancountries and China have strong impacts on the economy and energysectors of the region. The OECD2 projects a rather weak recovery forJapan, which is expected to register a zero or negative growth in 1998for the first time in more than two decades. This is expected to befollowed by only modest growth.

Population in the OECD Pacific region is assumed to increase byonly 0.1% per annum over the Outlook period, compared with 0.7%from 1971 to 1995. It is even expected to start decreasing at somepoint before 2020. The age structure of the population is expected toshift towards more older people. It is estimated that Japan’s working-age population, which peaked at about 90 million in the mid-1990s,will shrink to about 70 million by 20303.

The Japanese CIF import price for LNG has broadly followedcrude oil prices over the past two decades (see Figure 2.2, in Chapter2). It is assumed that LNG prices will increase from $126 per toe in1995 to $210 in 2020, following a path similar to that of crude oilprices. The price of internationally-traded hard coal is not expected toincrease substantially, due to abundant world supply.

Box 13.1: Regulatory Reforms in Japan and their Impacts

In recent years, an increasing number of countries have launchedambitious regulatory reform programmes to increase competitionand cost effectiveness. Energy is one of the sectors affected.

In May 1997, the Japanese Cabinet approved An Action Plan

2. OECD Economic Outlook, OECD Paris, June 1998.3. Japan Review of International Affairs, Fall 1997, pp. 219-233.


for Economic Structure Reform, in which deregulation measuresare proposed as a means of promoting market mechanisms tofulfil electric-power-load needs and improve the operation of thepetroleum market. The action plan builds on the Programmefor Economic Structure Reform (approved in December 1996)that aimed to ensure, through competition, that the electricity,gas and petroleum industries provide services at an internationalstandard of performance, including costs, by 2001.

The main objective of deregulation in the Japanese electricitysector is to bring electricity costs in line with internationallevels. Measures to achieve this goal include:

• improvements to the electricity system load factor throughactions by the government, utilities, manufacturers andusers, such as the promotion of heat-storage air conditioners,gas-fired air conditioners and load-reflective tariffs;

• more active use of independent power producers (IPPs)including a study of their possible supply capacity andtargets for their introduction;

• acceleration of utilities’ efforts to improve administrativeefficiency.

According to the report of the Study Group on theEconomic Effects of Deregulation, an advisory committee of theMinistry of International Trade and Industry (1997), theincrease in the efficiency of the electricity sector as a result ofderegulation would significantly lower electricity prices. Itwould ameliorate the price disparities that currently existbetween Japan and, for example, Germany, which has acomparable energy situation. Similarly, a general review ofpetroleum policies has been initiated with a goal of deregulationand institutional reform by 2001.

It is expected that regulatory reforms in general willstimulate economic growth by increasing productivity, whichlowers prices and creates additional demand for goods andservices. MITI estimates that, as a result of regulatory reforms,Japanese real GDP could be increased by 6 percentage pointsover time.


Table 13.1: Assumptions for the OECD Pacific Region


OverviewTotal primary energy demand in the OECD Pacific region

increased by 2.6% per annum in the period 1971 to 1995. Thiscompares with 1.2% in OECD North America and 1.3% in OECDEurope. Despite this relatively high growth, the OECD Pacific regionimproved its energy intensity level at an annual average rate of 0.9%.

In the business as usual case, primary energy demand is projectedto grow at an annual rate of 1.2% over the outlook period.Consumption of oil is expected to grow rather slowly, at 0.6% perannum. The present 51% share of oil in total primary energy demanddeclines to 47% in 2010 and to 44% in 2020.


1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal Price ($1990 per metric ton) 44 40 42 46 0.5%Oil Price ($1990 per barrel) 6 15 17 25 2.1%LNG price ($1990 per toe) n.a. 126 141 210 1.6%GDP ($Billion 1990 and PPP) 1249 2848 3856 4445 1.8%Population (millions) 121 147 153 153 0.1%GDP per Capita ($1000 1990 and 10 19 25 29 1.6%PPP per person)

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TPES 329 607 755 815 1.2%Solid Fuels 82 134 148 154 0.6%Oil 229 309 354 361 0.6%Gas 5 73 119 132 2.4%Nuclear 2 76 109 134 2.3%Hydro 9 11 12 13 0.8%Other Renewables 1 5 13 20 5.6%


Figure 13.1: Total Primary Energy Supply, OECD Pacific

As shown in Table 13.2 and Figure 13.1, future consumptionof gas, nuclear power and other renewables is expected to growstrongly. Gas increases its market share by 4 percentage pointsover the outlook period. Nuclear power in Japan, the onlycountry in the region with a nuclear programme, is expected toincrease by 2.3% per annum. Other renewables, mainly wind andgeothermal, grow rapidly, albeit from a low base in 1995.

As summarised in Table 13.3, total final energy consumptionis projected to grow at an annual rate of 1% over the outlookperiod. Electricity is expected to grow most rapidly, at an annualrate of 1.8%, which is identical to that assumed for GDP growth.Final gas demand increases at a significantly slower rate than thegrowth in primary gas demand, indicating a growing input topower generation. Oil is expected to grow at a slower rate thantotal final consumption, mainly driven by the demand formobility. Solid fuels demand is projected to stagnate over theOutlook period.

Solid Fuels22%

Other Renewables

1%Hydro2%

Nuclear13%

Gas12%

Oil51%

Solid Fuels19%

Other Renewables

2%Hydro 2%

Nuclear16%Gas

16%

Oil44%

1995 2020

607 Mtoe 815 Mtoe




Energy Related Services

Stationary SectorsAs seen in Table 13.4, stationary uses of fossil fuels are

expected to increase rather modestly over the Outlook period.There are many factors underlying this projection. A majorreason is the relocation of industries. As demand for steel fell inthe recession following the oil crises of 1973 and 1979, olderplants in OECD countries closed and new plants elsewhere weremore competitive. In the case of Japan, the trend in relocation toother countries of energy-intensive heavy industries, such as ironand steel, automobile and heavy engineering industries is animportant determinant of the slowdown in domestic fueldemand. Another reason for low growth rate for stationary fueldemand is the declining trend of energy intensities in manyheavy industrial branches. As illustrated in Figure 13.3, almostall major energy-intensive industries in Japan have experiencedsubstantial energy-intensity improvements, particularly in the1970s and 1980s, due partly to technological innovation. Forexample, the energy-intensity improvement in the iron & steeland chemical industries, which together account for about 50%of total industrial fuel demand, reached about 30% and 50%respectively over the past two decades. In this Outlook, furtherimprovements in energy intensity in the industrial sector areprojected.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TFC 257 424 516 547 1.0%Solid Fuels 45 52 49 49 -0.2%Oil 171 250 298 304 0.8%Gas 8 30 39 41 1.2%Electricity 34 90 122 141 1.8%Heat* 0 1 8 12 8.9%


Table 13.4: Energy Use in Stationary Services (Mtoe)


Figure 13.2: Energy Intensity Developments by Industry 1974=100

The projection of stationary fuel demand in stationary servicesreflects expected saturation for residential space and water heating inthe region. While oil is projected to retain the largest share ofstationary fuel demand, it is expected that gas will increasinglysubstitute for coal. Around 42% of incremental demand over theOutlook period is expected to be met by gas and the rest by oil. Thestrong increase in gas underlines the importance of Japanese long-termLNG supply and related trade linkages.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 173 220 246 251 0.5%Solid Fuels 44 52 49 49 -0.2%Oil 121 136 150 149 0.4%Gas 8 30 39 41 1.3%Heat* 0 1 8 12 8.9%

40

50

60

70

80

90

100

110

1974 1980 1990 1996

Iron & Steel Chemicals Ceramics & Cement Paper & Pulp


Figure 13.3: Energy Use in Stationary Services by Fuel

MobilityThe demand for mobility in the OECD Pacific region is expected

to rise along with GDP. The recent sharp increase can be explainedpartly by the shift to larger cars in Japan. The share of passenger carswith an engine capacity more than 2000 cc increased from 4.1% in1989 to 21.1% in 1996. The slowing down effect of the increase intransport fuel prices on demand for mobility due to increasing world oilprices after 2010 (see Chapter 2 for details) can be seen in Figure 13.4.It can also be seen that, during the 1990s and despite the economicslowdown in Japan, the energy demand for mobility has increased at aquicker pace than in the 1980s. As in other OECD regions, demand inthe OECD Pacific for transport-related services could show somesaturation, especially beyond 2010. This could arise from constraints onroad traffic, including congestion, limitations on infrastructuredevelopment and saturation in vehicle ownership levels. However,OECD Pacific car ownership levels are still significantly lower than inother OECD regions. In 1996, per capita passenger car ownership inJapan was about 0.37, compared to 0.52 in USA and 0.50 in Germany.It is also expected that changes in the GDP structure, away from heavyindustry towards services and towards lighter materials, could reducethe additional tonne-kilometres required for transport.

0

20

40

60

80

100

120

140

160

1000 1500 2000 2500 3000 3500 4000 4500


mill

ion

tonn

es o

il eq

uiva

lent


1971 - 1995

1996 - 2020


Figure 13.4: Energy Demand for Mobility

Figure 13.5: Ownership of Passenger Cars in Japan (More than 660 cc)

Source: The Japan Ministry of Transport.

Total energy demand for mobility is expected to grow by 1.2%per annum. Demand for aviation fuel is expected to increase fasterthan for road fuels, due to the effects of rising per capita income levelsand to the expected further decline in the cost of international travel.

0

20

40

60

80

100

120

140

160

1000 1500 2000 2500 3000 3500 4000 4500


mill

ion

tonn

es o

il eq

uiva

lent 1971 - 1995

1996 - 2020

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

660 and over to 2000 cc

More than 2000 cc

thou

sand

car

s


About 70% of the increase in total oil demand is projected to arisefrom increased mobility. By the year 2020, it is expected that the current37% share of mobility in total oil demand will have risen to 43%.


ElectricityTotal electricity demand in the OECD Pacific region is

projected to rise with increasing GDP. As seen in Figure 13.6, thisis broadly in line with the almost linear trend since 1971. Such alinear trend is associated with a decreasing GDP elasticity ofelectricity demand with a gradual decline from a level of 2 in the1960s to just over 1 at present. Over the outlook period, thiselasticity is expected to be about 1, a 1.8% electricity growthcompared to assumed GDP growth of 1.8%.


Strong demand growth leads to significant penetration ofelectricity in final energy consumption of the region. In 1971,electricity accounted for 13% of OECD Pacific final consumption; by1995, this had increased to 21% and it is projected to rise to 26% by2020.

The regulatory reforms in the electricity industry (see Box 13.1)or saturation of electricity uses in the household and services sectorscould affect these projected electricity demand trends.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 50 114 148 155 1.2%

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 34 90 122 141 1.8%


Figure 13.6: Total Final Electricity Demand

SupplyThis section provides an overview of the supply side of OECD

Pacific energy markets. While energy demand in this region isdominated by Japan, Australia is the major supplier of coal and gas.

Power GenerationElectricity generation in the OECD Pacific region is dominated

by Japan, which accounts for 82% of the region’s total generation.About half of Japan’s electricity supply comes from nuclear and oil-fired power plants, more than 80% of Australia’s electricity isgenerated by domestic coal and three quarters of New Zealand’selectricity comes from hydropower. The region’s electricity mix, for1995, is summarised in Table 13.7.

By the end of the projection period, annual power plant output inthe region could be 57% above its 1995 level, in line with the 1.8%per annum growth projected for electricity demand.

Electricity generated by solid fuels is projected to grow at anaverage annual rate of 1.2%, and its share in total generation coulddecline from 27% to 24%. Japan imports most of the coal it uses inpower stations. However, the utilities do buy a certain amount of

0

20

40

60

80

100

120

140

160

1000 1500 2000 2500 3000 3500 4000 4500Gross Domestic Product ($ Billion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020


domestic coal. Domestic coal is highly priced; in 1996, a tonne ofdomestic coal cost about 20000 Yen, whereas imported coal cost 5500Yen per tonne. The share of domestic coal in power station use hasbeen in decline; in 1982, it was two thirds of power station coal use,but only 15% in 1995. This share declined further after the closure ofJapan’s largest mine in March 1997.

Table 13.7: Electricity Generation Mix, 1995 (TWh)

As elsewhere in the OECD, natural gas is the fastest growing fuel;its use is expected to grow by 3.6% per annum over the projectionperiod and to increase its share in electricity output from 18% in 1995to 28% in 2020. All three countries have plans to increase gas use intheir power generation sectors. In Japan, where almost all fossil fuelsare imported, this will be in the form of imported liquefied natural gas(LNG). LNG is used, along with coal, to cover daily mid-load demandwhereas oil covers seasonal, mid- and peak-load demand. Smallincreases in gas-fired capacity are expected in Australia and NewZealand using indigenous resources.

Oil-fired generation is marginal in Australia and New Zealand,but accounts for more than 20% of electricity generation in Japan.Official plans call for oil-fired generation to fall to 8% of total by2010. However, as oil-fired plants have aged, pressure has beenincreasing to allow the replacement of oil-fired capacity. A study groupof the Electric Utility Industry Council argued that retiring oil-firedpower plants should be replaced by new oil-fired plants so as tomaintain an appropriate fraction of oil-fired generation in Japan’spower generation mix4. The share of oil is projected to decline from

4. Oil in Power Generation, OECD/IEA, 1997.

Australia Japan New Zealand Pacific

Solid Fuels 137 189 3 327Oil 3 224 0 227Gas 18 191 5 214Nuclear 0 291 0 291Hydro 16 82 27 126Other Renewables 0 3 2 5Total 173 981 36 1190


19% of total generation in the OECD Pacific in 1995 to 11% by2020. In absolute terms, oil-fired generation declines slightly from227 TWh to 204 TWh over the same period.

Nuclear power, concentrated in Japan, increases significantly; itsshare of total generation increases from 24% in 1995 to 28% in 2020.The first commercial nuclear plant in Japan was commissioned in1966 in Ibaraki prefecture. At the end of 1996, there were 54 reactorsin the country, with a total capacity of 44 GW.

Figure 13.7: Fuel Consumption in Power Generation

Nuclear power is considered by the Japanese authorities as animportant energy source in a country that lacks natural resources. Inaddition to reducing demand on imported oil and gas, it is seen as ameans of reducing environmental problems such as acid rain andglobal warming. The government’s target is to have 66 to 70 GW ofnuclear capacity by the year 2010. This means that more than 20 GWof new capacity will be needed over the next 12 years. At the time ofwriting, there is only one nuclear unit under construction: Onagawa-3, a boiling water reactor (BWR), of 796 MW is expected to becomeoperative in 2002 or 2003. There are four other units firmly

0

20

40

60

80

100

120

140

1000 1500 2000 2500 3000 3500 4000 4500


mill

ion

tonn

es o

il eq

uiva

lent

Solid Fuels Oil Gas Nuclear Hydro Other Renewables

1971 - 1995

1996 - 2020


committed. These are also BWRs with overall gross capacity of 4.7GW. We assume in this Outlook that by 2010, installed nuclearcapacity will be lower than the official target, at around 60 GW,reaching 73 GW by the end of the Outlook period. If Japanese nuclearpower plants operate for 40 years, then in the second half of theprojection period, a few plants could be decommissioned, requiringfurther nuclear plants to be built.

Over the past few years, public opposition to Japan’s nuclear powerprogramme has increased, following a number of nuclear incidents inJapan. In 1996, a referendum in the town of Maki in Niigata prefecturerejected the planned construction of the Maki-1 nuclear plant. InMarch 1997, Kyushu Electric announced the cancellation of plans tobuild a nuclear power plant5 in Miyazaki due to strong local protests.

Electricity generation from hydro power plants in the region isexpected to increase by 0.8% per annum. Most of the additionalhydro power production is expected to be in Japan as pumped storageto ease the daily peak. There is little activity in Australia and NewZealand. The latter already depends heavily on hydro power for itselectricity supplies, but there are no plans to build large new hydrostations because of their relatively high cost. There are plans toupgrade the large Manapouri station, which would add an extra 175MW by 2000, and some small-scale hydro plants are underconstruction6.

Hydro power in Japan gained momentum after the oil crises inthe 1970s. Most of the sites available for large-scale facilities have nowbeen used and recent development has been on a smaller scale. On theother hand, development of pumped storage facilities that provideelectricity for peak demand continues. Over the 25-year horizon of theOutlook, it is expected that about 7 GW of new conventional hydroplant and 10 GW of new pumped storage stations will be constructedin the region, largely in Japan.

Non-hydro renewable generation is set to increase seven-fold.Both Japan and New Zealand have geothermal energy; in 1995,production was 3.2 and 2 TWh respectively. Total geothermal capacityis expected to reach 3.3 GW in 2020. In New Zealand, geothermalenergy supplies about 6% of electricity and, depending on cost anddiscount rate assumptions, there is potential for an additional annual

5. Atoms in Japan, September 1996, Vol. 40, No. 8, pp 5-7.6. Energy Policies of IEA Countries, New Zealand, 1997 Review, IEA/OECD, 1997.

supply of 4.1 TWh. Wind and solar power generation are alsoexpected to increase, reaching 8.6 and 3.7 TWh respectively by 2020.

Table 13.8: Non Hydro-Renewable ElectricityGeneration (TWh) and Capacity (MW)

Over the Outlook period, installed generating capacity in theregion is expected to increase about one and a half times, from 274GW in 1995 to 426 GW in 2020. This is almost in line withelectricity demand, at an average rate of 1.8% per annum. However,more new plants will be needed, as some 55 GW of existing plant areexpected to be retired by the end of the Outlook period.

Table 13.9: Electricity Generating Capacity (GW)

Fossil fuel inputs to power stations increase 43% above their 1995levels by 2020. This increase is lower than the increase in thecorresponding output, due to efficiency improvements in generatingplants. Japan is already one of the most efficient countries in the worldin terms of power generation, but average fossil-fuel conversionefficiency could increase further with the increased use of CCGTplants rather than boilers for gas burning.


1995 2010 2020TWh MW TWh MW TWh MW

Wind 0.01 3 3.2 1050 8.6 2855Geothermal 5.3 756 14.5 2071 22.9 3272Solar 0.05 27 0.7 500 3.7 2800

1995 2010 2020

Solid Fuels 57 65 71of which CRW 4 5 5Oil 60 69 73Gas 58 101 128Nuclear 41 59 73Hydro 56 69 73Other Renewables 1 4 9Total 274 366 426


Table 13.10: Fuel Consumption in Power Generation (Mtoe)

OilIn 1996 OECD Pacific produced just 1% of global oil

production but accounted for 9% of global oil demand. The region istherefore a large net importer of oil, around 90% of demand in 1996and projected to rise to 96% by 2020.

Table13.11: OECD Pacific Oil Balance (Mbd)

In the short term Australian offshore oil production is expected toincrease, but the current low level of regional oil production meansthat the impact on the region’s net oil imports will be minimal. In thelonger term, OECD Pacific’s relatively modest remaining oil reservesof around 2.5 billion barrels (discovered and undiscovered) willprevent oil production from increasing. Cumulative regional oilproduction at the end of 1996 was around 4.5 billion barrels and so itcan be seen that this region has already produced the majority of itsoriginal oil reserves. Further information on the oil supply projectionscan be found in Chapter 7.

GasTable 13.12 presents the region’s gas balance until 2020. It is

1995 2010 2020

Solid Fuels 70 87 94of which CRW 5 5 6Oil 43 38 39Gas 41 77 89Nuclear 76 109 134Hydro 11 12 13Other Renewables 4 12 19Total 245 336 387

1996 2010 2020



important to note that the countries in this region are somewhatdifferent, for example whereas Japan is a large net gas importer,Australia is a large net gas exporter. Both countries are expected duringthe projection period to increase their respective roles as net importersand exporters.

Table 13.12: OECD Pacific Gas Balance (Mtoe)

Australia has substantial gas reserves and is a significant gasproducer and exporter. In 1996, Australia produced about 98% of thetotal OECD Pacific gas production equal to a total of 30 billion cubicmeters (bcm). About two thirds of this amount was consumed in thedomestic market and around 10 bcm was exported. In 1996, 95% ofthis gas was exported to Japan, and the rest to Turkey and Spain.

The Carnarvon basin provides about half of Australian gasproduction. It is assumed by the Australian Government that thecurrent gas export level will more than double by the year 2010. Inaddition, Australia has the world’s fourth largest coal-seam gasresources, after Russia, Canada and China. It is expected that thisindustry will develop during the coming decades7.

A specific feature of the OECD Pacific region is its dominant rolein the world LNG market. Almost all of Japan’s gas requirements areimported, and all in the form of LNG. About three-quarters is used inpower generation. In 1996, Japan accounted for 60% of the world’sLNG imports. Most of this gas comes from Southeast Asia, 40% fromIndonesia alone. The Asia-Pacific region is the world’s largest marketfor LNG, with Japan, the Republic of Korea and Chinese Taipeiaccounting for about three-quarters of total world LNG trade.

Japan’s contracted imports of LNG as of 1998 are up to 53.3million tonnes per annum. There is considerable uncertainty regardingthe new sources which will meet the expected 80% increase in gasdemand in the OECD Pacific by 2020. With natural gas demand in

7. Energy Policies of IEA Countries: Australia 1997 Review (IEA, 1997) provides a detailedassessment of gas production trends of Australia.

1996 2010 2020

Demand 73 119 132Supply 31 77 68Net Imports 42 42 64


Asia expected to grow substantially in the next two decades, additionalextensive investments in the region’s gas infrastructure, in particularpipelines such as those from East Siberia, are likely to be necessary.Such plans, however, are still in the very early stages.

Japanese LNG import prices are 30-40% higher than the borderprice of gas transported to European countries via pipeline, mainlydue to substantial costs of processing and transporting LNG. Despitethe 40% increase in the real LNG price assumed in the projectionspresented here, there is still considerable uncertainty about whetherthe expected demand can be met by available supply. However, it isassumed here that adequate investment for LNG capacity expansionwill be made and that Japan will not face a lack of physical supply overthe projection period.

CoalAustralia is the world’s largest exporter of coal. In 1996, its coal

production was 195 Mt, an increase of 2% over 1995. Since 1970,coal production has increased more than fourfold, making Australiathe world’s fifth largest coal producer with about 6% of the worldtotal. Most of the increase in production has been exported. Coalexports have risen from about 40% of total hard coal production in1970 to about 70% now.

Australian coal mines are close to the sea and within reasonableshipping distance of Asian markets where coal consumption isincreasing rapidly. Despite coal industry restructuring in Europe and,until recently, the embargo on South African coal, Australian exportsto Europe have not shown any consistent growth trend, partly becauseof high ocean freight costs.

Hard coal exports have increased by 8% per year since 1973,reaching 140.4 Mt in 1996. Steam coal exports rose more quicklythan those of coking coal. In 1980, steam coal represented 21% (8.9Mt) of total coal exports, but this rose to 45% in 1996 (62.8 Mt). Incontrast, coking coal exports rose from 33.8 Mt in 1980 to 77.6 Mtin 1996. Japan takes the largest share of Australian coal exports, 47%in 1996, followed by the Republic of Korea (14% in 1996) andEurope (11%). Exports to the Republic of Korea have risen over thepast few years, while exports to Europe have fallen. In the next twodecades, exports are likely to continue to account for the majority ofAustralia’s coal production.


So far, Japan has played a major role in establishing the referencecoal price in Asian markets. Real coal prices have been falling for overa decade. Australia-Japan benchmark prices for thermal and hardcoking coals have fallen by 2.5% and 3.4% a year in real terms from1985 to 19978. This trend reflects increased competition amongsuppliers with lower production costs because of higher labour andcapital productivity. An important feature of coal pricing in recentyears is the increased use of the spot market in Asian coal trade with areduction in the price premium for reference coal9. This is expected tointroduce a greater degree of transparency into the market and to keepprices low.

In this Outlook, coal prices are assumed to remain constant up to2010 in real terms and show a slight increase thereafter, mainly due toincreased freight costs. Although consumption growth is projected tobe significant, supply growth is expected to be sufficient to meethigher demand.

Comparison of Projections with Other OrganisationsThis section provides a general comparison of some other energy

projections with those presented in this Outlook. There are (at least)three other international organisations that produce long-term energyprojections for the OECD Pacific region; the Asia Pacific EnergyResearch Centre (APERC), the European Union (EU) and the UnitedStates Department of Energy (USDOE). For the sake of comparability,the comparison is based only on the business as usual cases of eachmodel. Table 13.13 gives the key assumptions for the models discussed.

Table 13.13: Comparison of Assumptions for the OECD Pacific Region

Note: Oil prices are quoted in real terms for the following years: APERC: $1995, USDOE: EU: $1993,WEO 98: $1990. LNG prices are quoted in $1990/toe.

APERC USDOE EU WEO 98Levels 1995 2010 1995 2020 1992 2020 1995 2010 2020Oil Price 17.0 17.0 17.0 22.3 17.6 31.0 15.0 17.0 25.0

Growth Rates 1995-2010 1995-2020 1992-2020 1995-2010 1995-2020GDP 2.6% 2.3% 2.1% 2.0% 1.8%Population 0.3% n.a. 0.3% 0.3% 0.1%

8. Coal Information, IEA/OECD, 1998.9. International Coal Trade, IEA/OECD, 1997.


APERC assumes the strongest increase in GDP while the WEO98 assumes the lowest. As for world oil prices, APERC assumes a flatprice, while EU, USDOE and WEO 98 all foresee future increases. Allthree organisations assume broadly similar price levels except for therather higher 2020 price assumption of the EU study.

APERC projectionsIn a recently published report10, APERC provides its first long-

term energy outlook for APEC member countries11. The projectionsare made on a country-by-country basis for the period 1995 to 2010.APERC uses a “hybrid methodology” that combines econometricmodelling and end-use approaches.

In order to compare the OECD Pacific projections of WEO 98 withthose of APERC, the projections of the latter for Japan and Australia areadded together. A comparison of projections is provided in Table 13.15.

APERC projects total primary energy supply to grow rapidly, atan annual rate of 2.2% against 1.2% for WEO 98. This can be mainlyattributed to the higher GDP growth rate assumption made byAPERC. APERC projects an average energy intensity decline of 0.4%per annum, as compared with 0.5% per annum for WEO 98.

Table 13.14 Comparisons of Projections of Total PrimaryEnergy Supply by Fuel for the OECD Pacific Region

There is a difference in the change in the market share of coal inTPES. While WEO 98 projects a market loss of 2 - 3 percentagepoints for coal for the period 1995-2010, APERC expects no increase.

10. APEC Energy Demand and Supply Outlook, APERC, 1998.11. These 18 countries are: Australia, Brunei Darussalam, Canada, Chile, China, Hong Kong(China), Indonesia, Japan, the Republic of Korea, Malaysia, Mexico, New Zealand, Papua NewGuinea, Philippines, Singapore, Chinese Taipei, Thailand, and the US.

APERC USDOE EU WEO 981995-2010 1995-2020 1992-2020 1995-2020

TPES 2.2% 1.3% 1.3% 1.2%Solid Fuels 2.3% 0.7% 1.0% 0.6%Oil 1.3% 1.4% 1.4% 0.6%Gas 4.5% 1.6% 0.3% 2.4%Nuclear 2.3% 1.2% 2.6% 2.3%Hydro/Other Renewables 3.1% 1.7% 0.3% 3.0%


This is mainly due to the differences in power generation projections,as illustrated on Table 13.15.

The oil share in the power input mix declines more rapidly inWEO 98 than in the APERC projections while WEO 98 projectshigher market penetration rates for gas. APERC projects nuclear’sshare as declining, also contrary to our expectations.

EU and USDOE ProjectionsBoth the EU12 and the USDOE13 provide long-term energy

projections for the OECD Pacific region on a regular basis. The EUmodelling approach includes the same countries as WEO 98 for thedefinition of OECD Pacific, while USDOE has the identical groupingof Industrialised Pacific countries. In terms of TPES, all three modelsproject a similar annual growth rate up to 2020 as shown in Table 13.14.

A striking feature of the EU’s projection is that gas demand is expectedto show almost no growth at TPES level. Both USDOE and WEO 98project gas to be the most rapidly increasing fuel type. For oil, EU and USDOE projections are higher than that of WEO 98. EU and WEO 98project similar growth trends for transportation, 1.3% and 1.2% perannum respectively. The main difference between the EU and WEO 98 oilfigures is in the assessment of the power generation sector. While WEO 98expects a declining trend of 0.4% per annum, the EU projects a doublingof oil in power generation, implying a growth rate of 2.6% up to 2020. Forhydro and renewable energy sources, both organisations projectsignificantly more conservative trends than does WEO 98.

Table 13.15: Comparison of Power Generation Projections

12. International Energy Outlook 1998 - With Projections to 2020, April 1998, DOE/EIA.13. Energy in Europe, European Energy to 2020 - A Scenario Approach, Directorate General forEnergy DGXVIII of the European Commission, 1996.

Electricity and 1995 APERC WEO 98CHP Plants Mtoe Share 2010-Share 2010-Share

Solid Fuels 70 29% 33% 26%Oil 43 18% 16% 11%Gas 41 17% 20% 23%Nuclear 76 31% 28% 32%Hydro 11 4% 3% 4%Other 4 2% 0% 3%Total 245 100% 100% 100%


Chapter 14 - Transition Economies 249

CHAPTER 14TRANSITION ECONOMIES1

This chapter describes the business as usual (BAU) energyprojection for the former centrally-planned economies of the SovietUnion and Eastern Europe. A common feature of these countries isthat they are at various stages in the transition to market economies.Following the dissolution of the Soviet Union in the late 1980s,disruptions occurred in the collection of energy statistics. Energy datareflecting the new economic order started to become available in1990, however, anomalies remain. Given the inadequacies of the GDPand the energy data for these countries, and the fundamental changestaking place in their economies, the margin for error associated withthe projection described in this chapter is much greater than for mostother regional energy projections in this Outlook. Because of theseproblems, the projections presented in this chapter have been preparedusing a simulation approach rather than one based on econometricmethods. The principal parameters used in constructing the energyprojections are shown below.

The values of the above parameters are highly uncertain anddepend on a number of factors such as future restructuring of theeconomy, energy prices in relation to costs of supply, energyconsumption metering and investment in new energy-using andenergy-producing capacity. Different values of these parameters wouldproduce different projections and the above tables are thereforedesigned to inform the reader of the values assumed rather thanprovide a definitive statement about their values.

1. This chapter covers the combined energy projections of non-OECD Europe (Albania, Bulgaria,Poland, Romania, Slovak Republic and Former Yugoslavia) and the Former Soviet Union(Armenia, Azerbaijan, Belarus, Estonia, Georgia, Kazakhstan, Kyrgyzstan, Latvia, Lithuania,Moldova, Russia, Tajikistan, Turkmenistan, Ukraine and Uzbekistan). Poland joined the OECDon 22 November 1996, but at the time that the energy projections were being developed for thisOutlook, Polish energy data had not been incorporated into OECD Europe. For statisticalreasons, this region also includes Cyprus, Gibraltar and Malta.


Table 14.1: Eastern European Parameters (excluding Russia)

Table 14.2: Russian Energy Parameters

Table 14.3: GDP Assumptions

Output/Income Driver ElasticitiesIndustry 0.9Commercial, Public Service, Residential and Non-Specified 0.8Agriculture 0.8Transport 1.1

Energy Price ElasticitiesIndustry -0.10Commercial, Public Service, Residential and Non-Specified -0.05Agriculture -0.10Transport -0.10

$ Billion 1990 and PPP 1995 2010 2020 1995 - 2020Annual

Growth Rate

Transition Economies excl. Russia 679 1061 1464 3.1%Russia 690 1086 1603 3.4%Total 1369 2146 3066 3.3%

Energy Efficiency Improvement per annumIndustry 0.6%Commercial, Public Service, Residential and Non-Specified 0.5%Agriculture 1.0%Transport 0.5%

Output/Income ElasticitiesIndustry 0.8Commercial, Public Service, Residential and Non-Specified 0.6Agriculture 0.9Transport 1.1

Energy Price ElasticitiesIndustry -0.2Commercial, Public Service, Residential and Non-Specified -0.1Agriculture -0.2Transport -0.2


The GDP assumptions used in the BAU projection for this regionare shown in Table 14.3.

Total Primary Energy SupplyDuring the period 1990 to 1994, energy demand and GDP in the

Transition Economies fell continuously. GDP, for example, declined atan annual average rate of 10.4%. By 1995, there was some evidencethat the Transition Economies had stabilised. This stability, however,masks considerable inter-regional differences, as economic recoveryand higher energy demand in non-OECD Europe was partly offset bycontinued decline in the former Soviet Union.

Figure 14.1: Transition Economies Energy and GDP 1990-1995

As Table 14.4 and Figure 14.2 indicate, the decline in TotalPrimary Energy Supply was spread across all fuels, with the exceptionof hydropower. Oil experienced the largest fall in demand, declining atan annual average rate in excess of 10% per annum. This rapid declinepartly reflects the desire of the region’s oil producing countries tomaintain oil exports at the expense of domestic oil demand.

0

200

400

600

800

1000

1200

1400

1600

1990 1991 1992 1993 1994 1995

mill

ion

tonn

es o

il eq

uiva

lent

0

500

1000

1500

2000

2500

$ Billion at 1990 prices and PPP

Total Primary Energy Supply GDP


Table14.4: Total Primary Energy Supply by Fuel (Mtoe)

Figure 14.2: Total Primary Energy Supply by Fuel (Mtoe)

TPES declined at a slower rate than did GDP. Energy intensitytherefore increased from 1990 to 1995, rising from 0.7 in 1990 to 0.8in 1995. To produce one unit of GDP in 1995 required 25% moreenergy than in 1990. One obvious problem with this comparison isthe development of a large black economy during this period, which

0

200

400

600

800

1000

1200

1400

1600

1990 1991 1992 1993 1994 1995

mill

ion

tonn

es o

il eq

uiva

lent

Hydro Nuclear Solid Fuels Gas Oil

1990 1991 1992 1993 1994 1995 1990 - 1995Annual

Growth Rate

Solid Fuels 412 374 357 341 309 300 - 6.1%Oil 473 461 416 347 278 275 -10.3%Gas 614 632 582 563 511 498 - 4.1%Nuclear 63 63 61 62 54 57 - 2.2%Hydro 24 25 24 25 25 25 1.2%Other -2 -1 0 -1 -1 -1 -11.0%TPES 1584 1554 1440 1336 1177 1154 - 6.1%


has resulted in some under-recording of GDP. If electricityconsumption were taken as a proxy for GDP evolution, then theunder-recording could be as large as 30%. The Transition Economiestrue energy intensity is unlikely to have worsened by 25%. There issome evidence that rather than rationalising production by closingfactories, and concentrating it in the most efficient plants, productionhas been maintained at low levels across many plants resulting in largeenergy overheads per unit of output.


Table 14.5 shows that in the BAU projection, the demand for gasgrows more rapidly than for any other fuel. Gas already has the highestshare of any fuel in the TPES fuel mix (43%). By 2020, gas isprojected to account for just over half of the Transition Economiestotal energy demand. Oil is projected to grow considerably moreslowly, but is still projected to grow twice as fast as coal demand. Thiswill result in oil overtaking coal to become the second most importantfuel in the fuel mix by 2020.

The relationship between TPES and official GDP has in the pastbeen erratic, as Figure 14.3 indicates. TPES is projected to grow at halfthe rate of GDP until 2010. Between 2010 and 2015, the oil price isassumed to increase from $17/bbl to $25. During this period, energydemand growth slackens, but begins rising again once the oil pricestabilises.

1995 2010 2020 1995 - 2020Annual

Growth Rate

Solid Fuels 300 357 360 0.7%Oil 275 329 390 1.4%Gas 498 647 835 2.1%Nuclear 57 67 48 -0.7%Hydro 25 29 32 1.0%Other -1 -1 -1 0.0%TPES 1154 1429 1664 1.5%


Figure 14.3: Total Primary Energy Supply versus GDP (1990-2020)

Total Final ConsumptionTotal final energy consumption (TFC) of energy fell continuously

between 1990 and 1995. Those fuels delivered by a fixedinfrastructure (gas, electricity and heat) declined less rapidly than fuelsthat require physical deliveries (solid fuels and oil). In several parts ofthe region, household consumption of gas and electricity is eitherunmetered or sold at a very low price. Therefore, little price-relatedincentive exists to reduce consumption.

Table 14.6: Total Final Energy Consumption 1990-1995 (Mtoe)

During the Outlook period, total final consumption is projectedto grow at an annual average rate of 1.7%, compared to 3.3% for

800

1200

1600

2000

1000 1500 2000 2500 3000 3500GDP ($ Billion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent

1990

2020

19911992

1993

1994

1995

1996

20102015

1990 1991 1992 1993 1994 1995 1990 - 1995Annual

Growth Rate

Solid Fuels 175 143 149 144 117 109 - 9.0%Oil 356 346 272 227 172 181 -12.7%Gas 318 296 277 245 227 232 - 6.1%Electricity and Heat 272 272 398 378 340 318 3.2%Total 1121 1057 1097 993 856 840 - 5.6%


GDP. Again, gas is projected to be the most rapidly growing fossilfuel. Among all energy types, electricity is projected to grow the mostquickly, at an annual rate of 3.4%. Despite electricity’s rapid growth,gas will remain the most important fuel, accounting for 33% of totalfinal energy consumption in 2020. The increased demand for gas islikely to arise primarily from industrial and heating end-uses.


Projections of total final energy consumption were prepared usingGDP as the main economic variable with a fixed elasticity, whichimplicitly assumes that the structure of GDP remains unchanged, orcontinues to change in the future in much the same way as in the past.The difficulties associated with underestimating GDP in this regionare well known, and the share of the service sector also tends to beunderestimated. Since the service sector is generally less energyintensive than industry, a failure to record its growing share in GDPmay have resulted in aggregate energy intensity being seriously over-estimated. Clearly, if the service sector’s share of GDP increases fasterthan it has in the past, as the OECD expects it is likely to do, thensome over-estimation of future energy consumption might also haveoccurred. The extent of this over-estimation will vary by country. Inthe case of Russia, its rich resource base means that it is likely to keepa high degree of heavy industry.

A factor restraining total final energy consumption in thesecountries is the low level of official per capita incomes which do notby definition take account of unrecorded income. Part of theunrecorded GDP will be increasingly included in official data betweennow and 2020 and this party explains the low GDP elasticity.

1995 2010 2020 1995 - 2020Annual

Growth Rate

Solid Fuels 109 119 121 0.4%Oil 181 240 296 2.0%Gas 232 332 428 2.5%Electricity 102 169 233 3.4%Heat 216 216 216 0.0%Total 840 1077 1295 1.7%


Table 14.8: Per Capita Income Comparison (Based on Official Data)

Figure 14.4: Total Final Energy Consumption versus GDP (1990-2020)

Stationary Sectors2

The general approach used in this Outlook to model thestationary sectors fossil fuel demands has been to model total energydemand and then to separately model individual fossil fuel shares. In thecase of the OECD regions fossil fuel share equations have been used thatinclude fossil fuel cross-prices. In the non-OECD regions a less formalapproach has been adopted, mainly because of data difficulties. In theseregions, such as the Transition Economies, a more judgmental approach

600

800

1000

1200

1400


mill

ion

tonn

es o

il eq

uiva

lent

2020

1990

1991

1992

1993

19941995

1996

2015

Transition Economies 1995 2010 2020

Population (millions) 395 395 396GDP per Capita ($1990 and 3470 5430 7749PPP per person)

OECD Europe 1995 2010 2020

Population (millions) 466 472 468GDP per Capita ($1990 and 14944 20774 24640PPP per person)


has been adopted that takes into account information on domesticproduction of fossil fuels (availability) and transmission networks etc.

Table 14.9 indicates how total fossil fuel demand in the stationarysectors varied from 1990 to 1995. Coal, oil and gas all declinedreasonably smoothly, but the heat series exhibited a marked increase in1992 and so cannot be used for comparison purposes as someproblems of data classification appear to exist.


Figure 14.5: Energy Consumption in Stationary Sectors versus GDP (1990-2020)

600

700

800

900

1000


mill

ion

tonn

es o

il eq

uiva

lent

1990

1991

1992

1993

1994

1995

2020

2. Note that in the case of this region, final consuming sector energy demand data are highlyuncertain. For example, industry’s use of oil for transportation has often been recorded as part ofindustry’s energy demand rather than under transport. Undue weight should not therefore beapplied to past movements in sectoral energy demand as they are sometimes the result of changingclassifications rather than actual variations in energy demand.

1990 1991 1992 1993 1994 1995 1990 - 1995Annual

Growth Rate

Solid Fuels 171 140 149 143 117 109 - 8.6%Oil 213 179 141 144 111 117 -11.2%Gas 312 290 232 231 214 219 - 6.8%Heat 140 142 274 263 236 216 9.0%Total 836 750 795 780 677 661 - 4.6%


Although energy demand in the stationary sectors is projected toincrease from its 1995 trough, it is not expected to surpass its 1990level until after 2010. Gas is projected to grow more quickly than theother fossil fuels reinforcing its dominant position in this sector.Consumption of heat, mainly in the form of district heating, is ofmajor importance in this region.

The relationship between energy demand and GDP during theprojection period is shown in Figure 14.5.


MobilityAs has already been noted, there are considerable problems with

the region’s transport sector energy consumption data, as it wascommon practice in the past to record industry’s consumption oftransport fuels under industry and not the transport sector. In anyevent, there is a clear downward trend in the Transition Economies’energy consumption. Some stabilisation of transport sector energydemand occurred in 1994-1995. Overall consumption in 1995 wasstill around half of its reported 1990 level.

Table 14.11: Energy Demand for Mobility (Mtoe)

1995 2010 2020 1995 -2020Annual

Growth Rate

Solid Fuels 109 119 120 0.4%Oil 117 142 165 1.4%Gas 219 311 399 2.4%Heat 216 216 216 0.0%Total 661 787 900 1.2%

1990 1991 1992 1993 1994 1995 1990-1995Annual

Growth Rate

Transition Economies 77 49 53 45 39 38 -13%excl. RussiaRussia 77 128 124 53 37 39 -13%Total 154 177 177 97 75 77 -13%


Given the difficulty in distinguishing between energyconsumption in the transport sector and other final consumptionsectors, projecting energy consumption in this sector is a particularlydifficult task. While acknowledging these difficulties, the followingchart presents the Outlook’s energy projection for the TransitionEconomies’ transport sector. Note that, as in the stationary sector, thetransport sector’s energy demand is not projected to exceed the 1990level until well after 2010.

Figure 14.6: Mobility versus GDP 1990 - 2020 (Mtoe)

Energy demand in this sector is projected to grow at an annualaverage rate of 3%, slightly less than that of GDP (3.3%). Currently,car ownership levels in the region are low by OECD standards and soenergy demand in this sector is likely to continue to expand for theforeseeable future.


50

100

150

200


mill

ion

tonn

es o

il eq

uiva

lent 1990

19911992

1993

1994

2020

1995

2015

2010

1995 2010 2020 1995 -2020Annual

Growth Rate

Total 77 120 162 3%


Electricity

Total final consumption of electricity has been shown in manycountries to be correlated with economic activity.


Electricity consumption fell considerably less rapidly than GDPduring the period 1990 to 1995 (4.9% versus 10.4% per annum), whichsuggests that some under-recording of GDP took place during thisperiod. As with the transport sector’s energy consumption data, there issome evidence of economic stability’s having returned in 1994 and 1995.

During the projection period, total final consumption ofelectricity3 is projected to grow at a rate slightly faster than that ofGDP, 3.4% and 3.3% espectively. In the short term, electricitydemand growth may be constrained by inadequate distributionnetworks and the small sizes of some apartments. In the longer term,electricity demand is likely to grow somewhat faster, as real incomesgrow and the demand for electrical appliances increases. The total finalelectricity consumption projection is shown in Figure 14.7.

3. Table 14.7 gives details of the electricity demand projection.

1990 1991 1992 1993 1994 1995 1990-1995Annual

Growth Rate

Transition Economies 57 60 59 54 49 49 -3%excl. RussiaRussia 74 70 66 61 55 53 -6.5%Total 131 130 124 115 104 102 -4.9%


Figure 14.7: Total Final Electricity Consumption versus GDP (1990 - 2020)

Power GenerationThe Transition Economies have significant variations in their

electricity output mix. Electricity generation in Poland andKazakhstan is almost entirely based on coal; natural gas is the mostsignificant source of power for Russia, Moldova, Uzbekistan andBelarus; Lithuania, Slovakia and Bulgaria generate large shares of theirelectricity from nuclear power; Tajikistan, Kyrgyzstan and Albania relyalmost exclusively on hydropower. In aggregate, the region relies mostheavily on coal and gas: in 1995 each accounted for about 30% ofelectricity production. The Russian Federation dominates the region,accounting for more than half electricity output.

Electricity generation in the region has been declining since 1990.In 1995, output had fallen to 1631 TWh, about the same level as in1981, and some 28% lower than in 1990. Over the Outlook period,economic growth is assumed to resume and demand for electricity togrow at an average annual rate of 2.9%.

Installed capacity in the Transition Economies stood at 434 GWin 1995. Solid fuels accounted for 32% of total capacity, oil for 11%,gas for 28%, nuclear for 9% and hydro for 20%. The averageutilisation factor was 43%, implying that there was substantial surpluscapacity in the region, although the availability of most plants is low

0

100

150

200

250

1000 1500 2000 2500 3000 3500


mill

ion

tonn

es o

il eq

uiva

lent

19901991

19921993

1994

1995

2020

1996

20152010


compared to that in OECD countries. Fossil-fired thermal plants, inparticular, operate at low load factors (mid or peak load), sincegeneration from nuclear and hydro has lower running costs and sothere is an incentive to operate these plants as much as possible (baseload). The surplus capacity is sufficient to meet some of the projectedgrowth in electricity demand and this has been taken into account inthe projection.

Over the Outlook period, a substantial increase in gas firedgeneration is projected, as gas supplies from Russia and the Caspianregion (mainly Turkmenistan4) become increasingly available. Theshare of gas in the output mix is projected to increase from 30% in1995 to 54% in 2020.

Table 14.14: Electricity Generation in the Transition Economies (TWh)

Coal will remain an important fuel for electricity generation.Although it is projected to lose share to gas, coal increases in absoluteterms from 498 TWh in 1995 to 770 TWh by 2020. Its share declinesover the same period from 31% to 23%. Oil-fired generation,currently accounting for 9% of the total, is projected to increase at 1%per annum. Its share could fall to 5% of the electricity generation mixby 2020.

Nuclear power is assumed to increase to 2010 and to startdeclining afterwards, as several nuclear power stations aredecommissioned in that period and capacity additions are notexpected to keep pace with retirements. Current capacity is about 41GW, most of it in Russia and Ukraine. By the end of the Outlookperiod, nuclear capacity in the region could be 29 GW.

4. Caspian Oil and Gas, IEA/OECD Paris, 1998.

1995 2020 1995-2020Annual

Growth Rate

Solid Fuels 498 770 1.8%Oil 140 179 1.0%Gas 487 1793 5.4%Nuclear 216 181 -0.7%Hydro 290 375 1.0%Total 1631 3298 2.9%


Table 14.15: Nuclear Power Statistics, 1995

Romania’s first nuclear plant, the Canadian built Cernavoda-1(660 MW), came on line in 1996. A number of reactors are underconstruction in the region. The following plants could be operationalaround the year 2000:

• the 2x388 MW Mochovce plant in Slovakia• Khmelnitski-2 (950 MW) and Rovno-4 (950 MW) in Ukraine • Rostov-1(950 MW), Kalinin- 3(950 MW) and Kursk-5 (925

MW) in Russia.

All of these are of Russian VVER design with the exception ofKursk-5 which is an RBMK type of reactor. More nuclear plants couldbe built in the longer term, although the ability to finance theseprojects remains uncertain. Russia has plans to build several reactors inSiberia and the Far East. Lack of funding for new plant may lead to anextension of the lifespan of some of the older reactors.

Hydropower in the region is assumed to increase at 1% perannum, bringing installed capacity from 88 GW currently to 104 GWby 2020. Part of the incremental capacity could come from upgradingexisting plants.

Combined heat and power is widely used in the region, but thequality of the available data is poor and it is very difficult to makefuture projections. It is, however, widely reported that conversionefficiencies are low and losses high. Large scale CHP facilities couldprogressively be replaced by small-scale and more efficient gas-firedCHP plants.

Installed Capacity (GW) Output (TWh)

Russia 19.9 99.5Ukraine 12.1 70.5Bulgaria 3.5 17.3Lithuania 2.8 11.8Slovakia 1.6 11.4Slovenia 0.6 4.8Armenia 0.4 0.3Kazakhstan 0.1 0


Most of the coal used in the region is of low quality and has muchhigher ash and sulphur content than those considered to be economicin OECD countries5. In 1995, brown coal accounted for 37% of coalinputs to power stations compared with 18% in the OECD. InPoland, higher grades of coal are exported and only the lower gradesare used for domestic consumption. Use of low-quality coal combinedwith an absence of environmental pollution control equipment has ledto acute environmental pollution problems in Central & EasternEuropean countries, particularly acid rain. Some efforts have beenundertaken by countries in the region to improve the environmentalperformance of coal-fired plants. Low NOx burners are being installedin Poland and there are plans to use them in Bulgaria and Romania;circulating fluidised bed combustion is being installed or planned inPoland and Romania; electrostatic precipitators are widely used,although they are often inefficient; several flue gas desulphurisationsystems have been installed or are planned in Poland, Russia andUkraine6.

Electricity tariffs in the region are low compared with OECDcountries, and, unlike the OECD, residential sector tariffs are lowerthan industrial tariffs7. An important problem is non-payment ofelectricity bills by customers (especially industrial and governmentbodies). Even the countries themselves are often unwilling or unableto pay for their electricity imports or imported fuel supplies togenerate electricity. Such practices have left the power sector withoutsufficient working capital and investment funds.

Reform of the electricity sector will be necessary to financeadequate maintenance and growth and to ensure that electric utilitiesare financially viable. Such reforms will also be necessary in order tocreate a level playing field encouraging investment in existing and newassets and allowing greater competition. Most of the countries in theregion have already started this process.

Fossil Fuel SupplyThe individual chapters on oil, gas and coal describe the regional

supply prospects for each of these three fuels. The following tablepresents the 1995 energy balance for the Transition Economies as agroup.

5. Air pollution control for coal-fired power stations in Eastern Europe, IEA Coal Research, 1996.6. op. cit.7. European Bank for Reconstruction and Development, Transition Report, 1996.


Table 14.16: Transition Economies Energy Balance 1995 (Mtoe)

Source: Energy Statistics and Balances of non-OECD countries 1994-1995, IEA/OECD Paris, 1997.

OilOil production is projected to recover from the sharp decline

since the dissolution of the Soviet Union. In the short to mediumterm, the region’s oil supply has the potential to recover more quicklythan demand. In the longer term, rising domestic oil demand is likelyto reduce net exports of oil.

Table 14.17: Transition Economies Oil Balance - Million Barrels per Day

Chapter 7 discusses the many uncertainties surrounding theestimation of oil reserves and future oil production. These problemsare particularly acute for the FSU, as Soviet oil reserve estimatesincluded oil that is considered neither economically or technicallyrecoverable and substantial quantities of unconventional oil.

Many Russian oil fields suffer from a lack of maintenance andinvestment. Future production from these fields is therefore heavilydependent on new expenditure on production facilities. Productionfrom the largely untapped Caspian Sea area is currently hindered by

Non-OECD Europe FSU Transition Economies

Indigenous Production 168 1204 1372Imports 87 4 91Exports -36 -248 -284Net Imports 52 -244 -193Marine Bunkers -1 0 -2Stock Changes 1 9 9TPES 219 968 1188

1996 2010 2020 1996 - 2020Annual

Growth Rate

Demand 5.5 7.2 8.5 1.8%Supply 7.3 10.2 9.4 1.1%Net Imports -1.8 -3.0 -0.9 -2.8%


limited export routes8. Only when the major problems in the CaspianSea area have been settled, such as pipeline routes and sovereigntyissues, is oil production likely to expand rapidly. The date by whichthese outstanding issues are likely to be settled is highly uncertain andso is therefore the future oil production profile from this province.

For the purposes of the BAU oil supply projection, Table 14.18sets out the assumptions made for the region’s oil reserves.

Table 14.18: Transition Economies Conventional Oil Reserves (Billion Barrels)

Table 14.18 presents the Transition Economies ultimate oilreserves including the contribution made by new technologies andbetter information after 1996. The important point to note is thatallowing new information and technologies to increase the level of oilreserves results in the region’s ultimate oil reserves varying with time.It is the enhanced estimate of ultimate oil reserves of 361.9 billionbarrels that determines the date at which the peak in the TransitionEconomies oil production will occur.

Total remaining recoverable oil reserves are of the order of 150billion barrels. This is a large quantity, and further emphasises thepoint that infrastructure improvements (pipelines, maintenance andoil field investment) are a key factor in raising the region’s oilproduction. With the exception of the Caspian area, the rest of theregion is a mature province with average output per well less than 100barrels per day. In such a context, close to the average of the US lowerstates, investment and technology deployment are likely to be themajor determinants of the region’s future oil production.

GasGas production is also projected to increase during the period

1995 to 2020. Full details of the gas production projection for this

8. A recent IEA publication examines the Caspian Sea’s future prospects in some depth, seeCaspian Oil and Gas, IEA/OECD Paris, 1998.

Cumulative Oil Production (end 1996) 134.1Remaining Discovered Reserves (end 1996) 99.8Undiscovered Oil Reserves (end 1996) 48.9Additional Reservers from new technology and information 79.1

Ultimate Oil Reserves 361.9


region can be found in Chapter 8. Table 14.19 summarises the mainfeatures of the gas balance during the projection period.

Table 14.19: Transition Economies Gas Balance 1995 - 2020 (Mtoe)

Gas exports rise by 5.5% per annum, mainly to meet OECDEurope’s rising demand. The widespread introduction of CCGTs intoOECD Europe’s power generation sector and falling indigenous gasproduction in the region after 2010, provides the TransitionEconomies with a ready market for their substantial gas reserves.Exports of gas double as a percentage of total gas production, fromunder 13% in 1995 to over 25% by 2020. These large exports of gastogether with huge oil exports, will provide the Transition Economieswith the much needed hard currency revenue. These revenues arelikely to provide a useful shelter under which the long-termrestructuring of the region’s economy can proceed.

Only a minority of countries in this region are likely to be net gasexporters, but several countries, such as Ukraine and Belarus, are expectedto earn substantial revenues for allowing gas to pass through their territoryto OECD Europe. In the longer term, the structure of gas exports fromthe region is likely to change, as Siberian exports will have to increasinglycompete with large quantities of gas produced in the Caspian area.Currently Caspian gas exports are expected to enter OECD Europe viaTurkey, rather than taking the northern Black Sea route, as the latter routewould require Russian agreement to transport the gas. Such an agreementis unlikely to be easily forthcoming since Turkmen gas (for example)would be in direct competition with Russia’s own gas exports.Furthermore, European gas consumers are likely to push fordiversification in both their origin of gas and in its transport route.Currently, Turkmen gas is expensive when compared to imports intoOECD Europe from Algeria and Russia, but this position could changetoward the end of the projection period when both of these countries willbe much higher up their gas supply curve than is currently the case.

1995 2010 2020 1995 - 2020Annual

Growth Rate

Indigenous Production 585 809 1116 2.6%Net Imports -74 -162 -281 5.5%TPES 498 647 835 2.1%


CoalThe Outlook for coal production is highly uncertain. The FSU’s

coal reserves are the largest in the world, accounting for 23% of theworld reserves. Coal production from the FSU, however, makes up amuch smaller share of global output then its coal reserves wouldsuggest, at just 8.5%. The region’s future coal production will dependheavily on its ability to compete successfully in the international coalmarket. For this to happen, current restructuring plans in Poland,Ukraine and Russia must be successfully implemented. The currentoutlook for these restructuring plans is not good, and the region’s coalexports are assumed, at best, to stabilise at current levels.

Comparisons with Other Organisations’ Projections

Energy DemandThis section compares the Outlook’s BAU energy projection with

equivalent projections prepared by the United State Department ofEnergy and Energy Information Administration (USDOE)9. TheEuropean Union (EU) also produced a set of energy projections forthis region in 1996, but the base year used in those projections was1990 and not 1995. Given that for several fuels and end-uses thechanges in demand that occurred from 1990 to 1995 are of a similarmagnitude to that projected for 1995 to 2020 in the Outlook’sprojection, a direct comparison with the EU’s projection is notpossible. The USDOE projections are shown below.

Table 14.20: Annual Growth Rates of Total Primary Energy Supply (1995 - 2020)

* The USDOE projection does not distinguish between these three different energies instead an“Other” category is shown.

9. International Energy Outlook 1998 - With Projections Through 2020, USDOE/EIA-0484(98),April 1998, Table A2, page 134.

USDOE IEA BAU

Solid Fuels -0.6 0.7Oil 2.2 1.4Gas 2.4 2.1Nuclear 0.5 -0.7Hydro 2.1 * 1.0Other Renewables 2.1 * -1.5Other Primary 2.1 * 0.0Total 1.7 1.5


At first sight, there would appear to be a number of differencesbetween the two sets of energy projections. However, given the dataproblems and other uncertainties, these differences are not verysignificant. Both projections suggest total energy demand will grow byaround 1.5% per annum. Both projections also show gas as the mostrapidly growing fuel, followed by oil. Although the two projectionspredict different paths for coal and nuclear, the annual average growthrates are less than plus or minus 1%. In both projections nuclear andcoal are largely stagnant during the projection period. “Other” fuelsare dominated by hydro, according to IEA statistics. In the BAUprojection, hydro increases from 25 Mtoe in 1995 to 32.3 in 2020, anannual average growth rate of 1%. If the USDOE’s “other” fuelsprojection starts at 25 Mtoe in 1995 then it grows to 42 Mtoe by2020. Given that both sets of projections suggest that TPES willexceed 1500 Mtoe in 2020 a difference of 10 Mtoe in the “other” fuelscategory is marginal.

The USDOE and IEA appear to be telling broadly similar storiesabout how the Transition Economies energy demand will developduring the period 1995-2020. Some differences do exist, such as theUSDOE’s higher growth rate for oil consumption, but thesedifferences are small when measured against the huge uncertaintiesthat surround the region’s future.

Energy SupplyOn the supply side, the USDOE publishes only oil production

capacity projections. It is, however, highly unlikely that the TransitionEconomies will do anything but produce at full capacity, whether it bepipeline capacity or oil field capacity, and so a direct comparison withthe BAU oil production projections is possible. The following tablesummarises the main features of the comparison.

The USDOE reference case projection is much more optimisticthan the BAU projection on both demand and supply. In 2020, oildemand is 1.6 Mbd higher and oil supply 4.2 Mbd higher than in theBAU projection. Thus, even with higher oil demand, the USDOEexpects oil exports to double between 1996 and 2020, although, as inthe BAU projection, there is some decline in net exports after 2010,as increases in domestic oil demand start to outstrip oil production.An important consequence of the USDOE’s oil production forecast isthat oil exports remain at relatively high levels and this reduces the


quantity of non-conventional oil that may be required to balanceworld oil demand and supply.

Table 14.21: Transition Economies Oil Balance (Mbd)

While the Caspian Sea is effectively a new oil province, oilproduction in many other parts of the FSU is mature. On the basis ofthe oil reserves estimates used in the IEA’s oil supply model, the FSUhad already produced 37% of its ultimate oil reserves by 1997. TheHubbert Curve peak in the FSU’s oil production occurs around 2012in the BAU projection, when cumulative oil production surpasses50% of ultimate oil reserves. Since the USDOE’s oil productioncontinues to expand beyond 2012 the USDOE must be assuming ahigher level of remaining oil reserves, or else there is no link betweenoil production and oil reserves in the USDOE oil model. For example,the USDOE presents analysis for the Caspian Basin which shows that,while minimum expected oil reserves are only 32.5 billion barrels,there are another 186 billion barrels of potential resources10. It isimportant to note that potential resources have a much lowerprobability of actually being produced than proven reserves, becausethe former are based on seismic and other tests rather than actualdrilling. When the USDOE’s proven reserves and potential resourcesare added together, the result is in an estimate of total resources of

IEA -BAU 1996 2010 2020 1996 - 2020Annual

Growth Rate


USDOE - Reference Case 1996 2010 2020 1996 - 2020Annual

Growth Rate


10. See page 34 of International Energy Outlook 1998: With Projections Through 2020,USDOE/EIA - 048(98).


218 billion barrels for the Caspian Basin. If such a large oil reserveestimate for the Caspian Basin is added to the estimated oil reserves forparts of the region, the USDOE’s oil production forecast becomesfeasible. Since, however, over 85% of the USDOE’s Caspian Basin oilresources are potential, not proven, reserves, the USDOE’s oilproduction forecast is likely to be towards the top of the range ofpossible oil production forecasts.

SummaryThe central theme of this chapter has been uncertainty, both on

the demand and supply sides of the energy balance. All the countriesin this region have been undergoing fundamental changes in recentyears. Trying to project energy demand and supply for these countriesin 25 years time is not an easy task. The energy projections presentedin this chapter should therefore be considered as work in progress andlikely to change as the region develops and our knowledge baseexpands.


Chapter 15 - China 273

CHAPTER 15CHINA1

IntroductionThis chapter provides a summary of China’s energy situation and

examines likely energy developments over the period to 2020. Theobjective is to increase the understanding of China’s energy system andits driving forces as well as to present the underlying uncertainties,rather than to forecast energy developments over the next 25 years. Itis important to emphasise that the projections included in this chapterare based on a wide range of assumptions, some of which are made onrelatively scarce information. Data on much of the Chinese energysystem, and on important energy demand drivers, are rather poor orare available for a very limited period of time, making standardeconometric analysis difficult. Problems also exist for the mainmacroeconomic indicators, especially GDP and its components.

Even without data problems, the dramatic changes in the Chineseeconomy and energy system over the past 15 years would make anystandard econometric techniques inappropriate for derivingprojections. In the past, energy consumption was allocated rather thanindividually chosen. Policy mechanisms and the behaviour ofeconomic agents are in the process of substantial change. The modelunderlying the projections presented here is primarily an accountingframework. The main drivers are assumed activity levels. Deregulationintroduces elements of market economies, like price signals. It isassumed that market reforms in China will continue. Price elasticitiesfor different fuels/sectors are imposed throughout the Outlook period.

There are many reasons for China’s growing importance ineconomic, energy and environmental terms. With a population of over1.2 billion, China is the most populous country in the world. If thesize of its economy is measured using purchasing power parities, it isthe second largest economy in the world2, after the United States.

1. In this Outlook, Hong Kong is included in China. Hong Kong became a SpecialAdministrative Region of China in 1997.2. The use of market exchange rates to make the comparison provides a significantly differentpicture. GDP calculated on a purchasing power parity approach is six times as large as that basedon market exchange rates.


China is one of the largest trading economies, ranking fifth after theEU, the US, Japan and Canada. China is likely to becomeprogressively more important if its economy continues to expand at ornear recent rates. This will lead to increasing influence both in thePacific region and in the world economy. Since China alreadyaccounts for more than a tenth of world carbon emissions, the way inwhich its growing energy needs will be met will be critical for its ownand the world’s environment over the next two decades and beyond.Table 15.1 highlights China’s increasing significance in the world.

Table 15.1: Importance of China in the World (Percentage of World Total)

* CRW - Combustible renewables and waste.

Given the specific nature of China’s economy, the Asian financialcrisis does not appear to have affected China as severely as elsewhere inthe region. However, China has not been completely immune to itsimpacts. It is expected that the Asian crisis could cause a decline inforeign investment.

China’s present level of primary energy consumption is equivalentto one-fifth of the OECD total and one-tenth of the world total. Itsexpected contribution to the increase in world energy consumptionover the Outlook period will be very important. For example, theprojected increase in China’s energy consumption is expected to beequal to that of the OECD, and to account for almost a quarter of theincrease in world demand, as shown in Figure 15.1.

Based on official Chinese statistics, its economic performanceover the past 15 years has been impressive, not only because of the fasteconomic growth achieved, but also because of the relatively modestgrowth in its energy needs. Between 1981 and 1995, China’s primary

1971 1995 2010 2020

GDP in PPP terms 3 12 17 20Population 23 21 20 19Primary energy demand (excl. CRW*) 5 11 14 16Primary energy demand (incl. CRW*) n.a. 12 14 16Coal Demand 13 28 33 36Oil Demand 2 5 8 10Power Generation 3 9 13 15CO2 Emissions 6 14 17 19


energy demand grew at more than 5% per annum, significantly lessthan the economic growth rate of over 9%. Such a decline in energyintensity is an achievement rarely accomplished in countries at thislevel of development. However, the reliability of country’s officialGDP statistics has been questioned. In the projections presented here,official GDP statistics have been used. The next section provides adiscussion of the statistical measurement of China’s GDP.

Figure15.1: Shares in Incremental World PrimaryEnergy Demand (1995-2020)

One of the key features of the Chinese economy is its large shareof industry. This could be due to the political emphasis given to heavyindustry up until the early 1980s. The share of industry in GNP in thelast two decades did not change: it accounted for 48% in 1978, thesame as now3. However, the share of agriculture in GNP droppedsignificantly, from 28% in 1978 to around 20% in 1995, and theshare of the service sector grew from 24% in 1978 to 31% in 19954.

China is the second largest energy consuming country in theworld behind the US. The most striking feature of the Chinese energymarket is its extreme dependence on coal. In 1996, coal accounted formore than three quarters of primary energy supply and around two

China23%

OECD23%

OtherRegions

54%

3. For comparison, the share of industry in the GDP of OECD countries was around 40%, onaverage, in 1960 and has declined gradually to around 30% in 1995. 4. China Statistical Yearbook, State Statistical Bureau, China, 1996.


thirds of final commercial energy consumption. Oil accounted forabout 20% with gas and hydro sharing the remainder. Final gasconsumption in China is insignificant. This is used mostly for theproduction of chemicals and fertilisers. The share of electricity in finalconsumption, slightly higher than 10%, is low compared to othercountries, reflecting the low stage of economic development in China.Nearly three quarters of electricity generation is from coal-fired plantswith the bulk of the remainder coming from hydroelectricity.

These figures refer to commercial energy use. However, China isestimated to use about 206 Mtoe of non-commercial biomass energy.This currently represents about 19% of China’s total primary energydemand. Biomass energy consumption is analysed at the end of thischapter and in Chapter 10.

A specific feature of the Chinese energy system is the unevendistribution of energy resources between regions. While major coaland oil resources are in the North, the main energy consuming regionsare in the South. This underlines the crucial importance of thetransportation network.

Energy prices in China are, in varying degrees, controlled by thegovernment. Almost all fuel prices are significantly below fulleconomic costs. Since the early 1980s, successive Chinesegovernments have introduced different measures to reform the energypricing mechanism, but these efforts have been limited in scale. InJune 1998, following the Asian financial crisis and the oil price fall,the State Council decided to link crude oil prices closely to theinternational price on a monthly basis.

China’s GDP A major uncertainty for energy analysis of China is the quality of

China’s GDP statistics. It is widely agreed that the figures published byChina’s statistical authorities underestimate China’s GDP level andoverestimate the GDP growth rate, at least in the last two decades.

Two recent studies, both launched by the OECD DevelopmentCentre, have produced new estimates of China’s GDP usinginternationally accepted methodological approaches5. Both thesereports aim at providing more accurate and internationally

5. Measuring Chinese Economic Growth and Levels of Performance, Angus Maddison, OECD Paris,1997 and China’s Economic Performance in an International Perspective, Ren Ruoen, OECDParis, 1997.


comparable measures. Although the two authors do not use the sameapproaches, their findings are similar.

Maddison6, along with a number of other authors, claims thatofficial statistics tend to underestimate the level of national income inChinese currency, mainly for the following reasons:

• The current Chinese national accounts remain a mixture of theold Material Production System (MPS) and the United NationsSystem of National Accounts (SNA). Official statistics for someservice sectors are still weak.

• The national accounting system provides incomplete coverageof the national economy. Up to 1978, the Chinese nationalaccounting system did not include non-productive services,such as banking and insurance and passenger transport, whichare included in standardised national accounts of OECDcountries.

• Agricultural value-added is understated.Although some “non-material product” services have been

included since 1987, the notion of comparable prices, whichunderstates inflation, is still used to deflate national income in moneyterms in order to calculate growth rates in real terms. This means thatinflation rates have been underestimated and real economic growthrates overestimated in official Chinese statistics.

Maddison (1997) re-estimates Chinese GDP using a differentmeasurement technique, closer to western national accountingpractice, and making use of 1987 weights. He comes to theconclusion that for the period of 1952 to 1978, his overall GDPmeasure records an average growth rate of 4.4% per year, comparedwith the official growth rate of 6%. For 1978 to 1994, these figures are7.4% and 9.8% respectively. Similarly, Ren Ruoen (1997) madeseveral calculations for China’s GDP and found that applying aproducer price index to official GDP for the period of 1986 to 1994,produces 6% growth rate instead of the official 9.8%. Applying ICP-based dollar series (United Nations International ComparisonProject), he estimated GDP growth at 8.4%. A similar exercise withthe ICOP (International Comparison of Output and Productivity)provided 7.3%, all significantly below the official figure. Stronggrowth rates in some industrial sectors suggest that costs, prices and

6. See, e.g., World Bank (1992), China: Statistical System in Transition, Washington, DC, andX.H. Wu (1993) The “Real” Chinese Gross Domestic Product (GDP) for the Pre-reform Period,1955-1977, Review of Income and Wealth, Series 39, No. 1.


value-added have been declining as a result of economies of scale. Iftrue, this could lead to even lower measures of economic growth.

Table 15.2: Estimates of China’s GDP ($Billion 1990 and PPP) and GDP per Capita ($ per person)

Source: Maddison7 (1995) and IEA calculations.

Impacts on Energy AnalysisThe exceptionally rapid decrease of energy intensity of China has

been questioned by several authors. Based on official figures, Chinesecommercial energy intensity in the last 15 years has decreased by 5.6%per year on average. This trend contrasts with increases of 1.4% peryear for India and 1.2% for the East Asia region. Empirical evidenceshows that the “typical” energy intensity curve of a country increasesduring the development phase, then peaks and, after reaching a certainlevel of economic development, begins to fall. The opposite behaviourof energy intensity evolution in China has been explained as “unique”or “a result of statistical problems”. Using the GDP estimates ofMaddison (1997) for energy intensity calculations provides a “moretypical” picture. As can be seen in Figure 15.2, the decline of energyintensity is less sharp. By using Maddison’s figures, the averagecommercial energy intensity decline in the last 15 years falls to 3.4%per year. This dampens significantly the improvement in energyintensity officially claimed for China.

Alternatively, if one were to assume that the relationshipbetween energy consumption and GDP in China were similar to thatobserved in other developing countries, then the implied GDP growthrates, based on actual consumption of electricity and primary energy,would be less than the official figures.

7. Monitoring the World Economy 1820-1992, Angus Maddison, OECD Paris, 1995.

GDP GDP per capita

Kravis 4 834 4 264Summer and Heston (1993) 3 061 2 700Ren and Kai (1993) 1 983 1 749Ren and Kai (1994) 2 661 2 347Taylor (1991) 1 286 1 135Maddison (1997) 2 105 1 856Official Statistics 1 830 1 614


The same issue arises in the calculation of the income elasticity ofenergy demand, the main parameter determining long-term energydemand projections. Official statistics show an income elasticity ofroughly 0.5, while for a developing country one would expect a valueof around 1.

Figure 15.2: Comparison of Energy Intensities Based on Officialand Maddison GDP Figures (1978 = 100)

Although official GDP statistics are used for the projectionspresented here, the issue of the reliability of these figures represents akey uncertainty for this analysis.

In the business as usual case assumptions, the economy isprojected to grow at 5.5% per annum from 1995 to 2020. Theassumed GDP growth rates for China are consistent with official dataand are higher than those assumed for any other region in thisOutlook. If realised over the next 15 to 20 years, China would becomethe largest economy of the world in purchasing power parity terms. Itis assumed here that policy reform will continue in China. As state-owned enterprises still dominate the Chinese economy, problemsinvolved in transforming these enterprises and transferring themsuccessfully to the private sector, as well as bottlenecks in many criticalsectors of the economy, may dampen this assumed growth. It is

0

10

20

30

40

50

60

70

80

90

100

1978 1980 1982 1984 1986 1988 1990 1992 1994

Official GDP Maddison GDP


assumed that China will be successful in limiting growth inpopulation to an average of 0.8% per annum over the Outlook period.

Table 15.3: Assumptions for China Region

Energy Demand

OverviewUsing the same methodology (i.e. extrapolating past GDP and

related energy growth), primary energy demand in China is expectedto grow at 3.6% per annum over the Outlook period. This increase islower than historical growth rates (5.5% in the period 1971 to 1995).The difference can be attributed largely to slower economic growth.It is assumed that, as a result of increased liberalisation in manysectors, fuel prices will begin gradually to play a role in energyconsumption decisions and slow energy demand growth. Theseassumptions lead to a further decline of energy intensity by 1.8% perannum on average.

In terms of total primary energy demand, solid fuels are expectedto grow the slowest, at 3.1% per annum. As a result, the current 77%market share of solid fuels declines by about 10 percentage points by2020, but solid fuels remain dominant. The main driver of solid fueldemand is power generation. Oil demand is projected to grow by4.6% per annum, resulting in a significant market share increase by2020. Gas is expected to grow very strongly, at 6.5% per annum, butits share of total primary energy demand remains limited. Asdiscussed in the power generation section, in order to meet the highelectricity demand growth, both nuclear and hydro power plants areexpected to increase their shares in the primary energy mix. Over the

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal price ($1990 per metric ton) 44 40 42 46 0.5%Oil price ($1990 per barrel) 6 15 17 25 2.1%LNG price ($1990 per toe) n.a. 126 141 210 2.1%GDP ($Billion 1990 and PPP) 484 3404 8426 13123 5.5%Population (millions) 845 1206 1372 1469 0.8%GDP per capita ($1000 1990 and 0.57 2.82 6.14 8.93 4.7%PPP per person)


Outlook period, nuclear is expected to grow by 9.6% and hydro by5.5% per annum.


Figure 15.3: Total Primary Energy Supply

As shown in Table 15.5, total final consumption is projected toincrease by 3.5% per annum to 2020. Electricity is expected to growthe most rapidly, followed by heat and gas. Final solids demand isprojected to grow by only 2.4% on average, reflecting significant lossof market share in the industrial and residential/commercial sectors.

Solid Fuels77%

Hydro/Other 2%

Nuclear 0%Gas 2%

Oil19%

Solid Fuels67%

Hydro/Other 3%

Nuclear 2%Gas 4%

Oil24%

1995 2020

864 Mtoe 2101 Mtoe

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TPES 239 864 1559 2101 3.6%Solid fuels 190 664 1087 1416 3.1%Oil 43 164 355 506 4.6%Gas 3 17 57 81 6.5%Nuclear 0 3 19 33 9.6%Hydro 3 16 39 62 5.5%Other Renewables 0 0 2 3 -



Stationary Sectors

As shown in Table 15.6, energy demand in stationary uses offossil fuels is projected to increase at 3% per annum, more thandoubling over the Outlook period. The main expected change in theresidential/commercial sector fuel mix is the rapid penetration of oiland gas at the cost of coal. Partly for environmental reasons, officialpolicy encourages the use of gas in residential areas. Gas networksalready exist in many large cities, although much of the gas used isderived from coal. In rural areas, coal will continue to be the majorfuel, increasingly substituting for non-commercial biomass. Futuretrends in residential/commercial energy demand will largely dependon: the speed of substitution of non-commercial fuels by commercialenergy (mainly in rural areas); the increase in building space for bothresidential and commercial purposes; efficiency trends of newbuildings and appliances; and the rate of appliance penetration, whichdepends in turn on growth in household disposable income.

The industrial sector in China accounted for about 66% of totalfinal energy consumption in 1995, an unusually large proportionwhen compared with other countries. In the OECD, for example, theindustry sector accounted on average for only 31%, while in theRepublic of Korea the share of industry was around 47% in 1995. Asfor fuel mix, it is expected that, as in the residential/commercialsector, the coal share will decline and the oil and gas shares will grow.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TFC 195 649 1145 1524 3.5%Solid Fuels 147 416 617 755 2.4%Oil 37 132 280 395 4.5%Gas 1 13 36 47 5.2%Electricity 10 68 165 255 5.4%Heat 0 19 46 71 5.3%


Figure 15.4: Energy Use in Stationary Sectors by Fuel

Table 15.6: Energy Use in Stationary Sectors by Fuel (Mtoe)

In preparing the projection of energy demand in the industrial sector,special attention was paid to the iron & steel and chemical industries, dueto their combined share of total industrial fuel demand of about 50%.About 85% of energy consumption in the iron and steel industry is coaland oven coke. China appears to be one of the most steel-intensivecountries in the world8. The Chinese steel industry uses, on average, one-

0

100

200

300

400

500

600

700

800

0 2000 4000 6000 8000 10000 12000 14000


mill

ion

tonn

es o

il eq

uiva

lent


1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 179 521 850 1079 3.0%Solid Fuels 147 409 610 748 2.4%Oil 31 80 157 213 4.0%Gas 1 13 36 47 5.2%Heat 0 19 46 71 5.3%

8. As with energy intensities, international comparisons of steel intensities are subject to severeinterpretation and measurement problems. See the 1996 edition of the IEA’s World Energy Outlookfor a detailed discussion of energy demand in the iron & steel sector.


third more energy per tonne of steel than the US industry. Similarly, in thechemical industry, the use of coal as a feed stock in small-scale plantsinvolves large inefficiencies. Future heat demand trends will be largelyaffected by the patterns of technological development in industry.

MobilityChina’s energy demand for mobility is low, both in absolute terms

and in comparison with the total energy used in the country. In 1995,energy used in transportation was 33% of total final energy demand inOECD countries and 23% in developing countries as a whole, butonly around 9% in China9. The Chinese demand for mobility isprojected to grow broadly in line with GDP over the Outlook period.As shown in Table 15.7, total demand for mobility is expected to growat 4.8% per annum to the year 2020, more than tripling in thisperiod. This expected growth is almost the same as the assumedincrease average GDP per capita for the period.

Figure 15.5: Energy Use for Mobility

A key uncertainty for projections of mobility is the future increasein vehicle ownership in China. Currently, passenger vehicle ownership

0

20

40

60

80

100

120

140

160

180

200

0 2000 4000 6000 8000 10000 12000 14000Gross Domestic Product ($ Billion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent 1971 - 1995

1996 - 2020

9. Due to the methodology of data collection in China, the official numbers on oil consumptionby the transportation sector, as reported by IEA Statistics, are very likely to be underestimated.


per 1000 people is about 3 compared with 27 for Thailand and 498for Germany10. Official policies may play a role in affecting futureprivate car ownership trends.


ElectricityChina’s electricity demand more than doubled in the last decade

and is projected almost to quadruple by 2020. As shown in Figure15.6, electricity demand rises linearly with income. It is expected thatelectricity demand will increase at 5.4% per annum over the Outlookperiod, almost equal to the assumed GDP growth rate. In 1995, about68% of electricity was consumed in the industrial sector and 23% inthe residential/commercial sector.


0

25

50

75

100

125

150

175

200

225

250

275

0 2000 4000 6000 8000 10000 12000 14000


mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 6 59 130 190 4.8%

10. World Road Statistics ’98, International Road Federation, 1998.



As a result of technological innovation and an assumed shift inthe industrial structure towards less energy intensive industries, it isexpected that electricity will substitute for coal in many industries overthe Outlook period. In the residential/commercial sector, energydemand growth will be increased by the further penetration ofelectrical appliances. As shown in Table 15.9, the level of electricalappliances has grown at high rates in the last decade, mainly as a resultof increasing income levels. The penetration of refrigerators hasincreased by 10 times in urban households and about 50 times in ruralhouseholds over the last ten years. The penetration of washingmachines in urban households has grown to almost 90% in 1995 fromless than 50% in 1985, and to 17% from 2% for rural households.Penetration ratios for television sets and electric fans are alreadybeyond 100% in urban households, and more than 80% in ruralhouseholds. Based on these past trends and expected strong growth inincome per capita, it is very likely that penetration of many applianceswill continue to grow and strongly affect the future trends ofelectricity demand. Only about 80% of the population is nowconnected to China’s electrical grid so that continued electrification inrural areas over the Outlook period will be another factor forincreasing electricity demand.

Table 15.9: Ownership of Major Durable Consumer Goods per 100Households

Source: China Statistical Yearbook, State Statistical Bureau, China, 1996.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 10 68 165 255 5.4%

Urban Rural1985 1990 1995 1985 1990 1995

Washing Machines 48.3 78.4 89.0 1.9 9.1 16.9Refrigerators 6.6 42.3 66.2 0.1 1.2 5.2Television Sets 84.6 111.4 117.8 11.3 44.4 80.7Electric Fans 73.9 135.5 167.4 9.7 41.4 89.0


Supply

Power GenerationIn 1995, electricity generation in China was 1036 TWh, three

quarters of it from coal-fired plants. In the BAU projection, electricitygeneration grows at 5.4% per annum to reach 3857 TWh in 2020. In1995, nearly a quarter of the output of electricity and CHP plants washeat. Demand for heat is projected to grow in tandem with electricitydemand.

Table 15.10: Electricity Generation in China (TWh)

Installed electricity generating capacity in 1995 was 227 GW. Ofthis, 70% was coal-fired, 23% hydro, 6% oil-fired and the remaining1% split among gas-fired and nuclear. During the past 6 years, annualadditions to capacity have been on the order of 16 GW. Theseadditions have helped reduce power shortages.

Over the Outlook period, total capacity is projected to increase by530 GW. By 2020, installed capacity could reach 757 GW with 62%in the form of coal-fired facilities, oil maintaining its current share,nuclear and hydro increasing their shares to 3% and 26% respectively.Non-hydro renewable capacity increases in absolute terms, but itsshare of total capacity remains small; from 0.1% in 1995 it rises to0.6% in 2020.

The enormous growth of electricity demand in China is expectedto be met by its most abundant domestic resource, coal. The powersector is the second largest consumer of coal, after industry, takingabout a third of coal production. The power sector will continue torely on coal, although coal’s share in the electricity generation mix isprojected to decline to two-thirds, as some incremental demand forelectricity is covered by nuclear and hydro plants. Electricity

1995 2010 2020

Solid Fuels 767 1729 2612Oil 63 168 257Gas 2 65 123Nuclear 13 72 127Hydro 191 457 726Other Renewables 0 7 11Total 1036 2497 3857


generation from coal is projected to increase at 5% per annum, from767 TWh in 1995 to 2612 TWh in 2020. Inputs to power plantsincrease at a lower pace, due to efficiency improvements, at 4% perannum. By the end of the Outlook period, coal consumption by thepower sector could reach 648 Mtoe, or about 45% of primary coaldemand.

There are many problems associated with Chinese power plants,such as small unit size, inconsistent coal quality and low load factorsdue to low plant availabilities or lack of fuel. As a result, the averagethermal efficiency of electricity generation in fossil fuel plants rangesbetween 27% and 29%, compared to around 38% in OECDcountries. If heat output is included, then thermal efficiency in Chinais higher, around 41%.

Most coal plants in China are less than 300 MW in size. In recentyears, with demand for electricity increasing rapidly, several units of300 MW, and even 600 MW are being constructed. The larger unitswill eventually result in efficiency increases. There are also plans toretrofit or phase out some inefficient small plants. However, acuteelectricity shortages mean that small and medium size plants are stillbuilt, and older plants are kept in service. If this practice persists,efficiency is likely to remain low. If efficiency were to remain at presentlevels, coal consumption by 2020 would be 25% higher and CO2

emissions would be 10% higher than projected.China has extensive hydro-electric resources, about 675 GW, of

this amount 290 GW are economically exploitable. In 1996, hydro-power capacity stood at 56 GW and is assumed to reach almost 200GW by 2020. The most significant hydro project is the Three Gorges,on the Yangtze River. When completed, in about 2010, it will have acapacity of 18200 MW, from 26 generators with 700 MW each.Construction started at the end of 1994. The Yangtze River, the thirdlongest river in the world, was diverted from its natural course inNovember 1997, to clear the way for the construction of the world’sbiggest dam - 185 metres high and 1.6 kilometres wide. The projecthas raised various concerns, both in China and internationally. Itcould disturb the ecosystem in the region, it would force more than amillion people to be relocated and it would submerge archaelogicalmonuments.

Small increases in gas-fired capacity, particularly in coastal regionsand the south, could raise gas-fired generation to 123 TWh by 2020.There are many uncertainties about natural gas use in the power


sector, as priority is given to the residential sector and to thepetrochemical industry, mainly for fertiliser production. There havebeen discussions on LNG projects, particularly in southern andeastern China, where natural gas could compete with nuclear.Examples are a 5 GW project in the Yangtze River Delta and a 8x330MW complex in Shenzen province. China is also developing its owncombined cycle gas turbine technology. In general, imported LNG islikely to remain a high-cost form of generation over the Outlookperiod.

Oil-fired generation is projected to maintain a share of 6% to 7%in the electricity generation mix. In absolute terms, it is projected toincrease from 63 TWh in 1995 to 257 TWh by 2020. Oil could bepreferred for new power generation in some cases, particularly incoastal areas; an example is the Zhenhai combined-cycle power plant,near Shanghai.

China’s first nuclear plant became operational in 1991. This is a300 MW pressurised water reactor (PWR) of Chinese design withabout 70% of its components coming from Chinese sources. Theplant is located at Qinshan, south of Shangai, and provides electricityto Shanghai and three eastern provinces. The second nuclear plant isthe 2x900 MW Daya Bay complex, near Hong Kong, which absorbsabout 70% of the plant’s output. Construction began in 1987; the firstunit was commissioned in 1993 and the second in 1994. There arefour plants under construction. China plans to develop its ownadvanced nuclear reactors such as the AC-600 PWR. Official planscall for 20 GW of nuclear capacity by the year 2010 and 40 to 50 GWby 2020. The most ambitious of China’s nuclear projects is theYangjiang power complex, 250 km southwest of Hong Kong. Theplant, currently under feasibility study, would be the country’s largest,with six 1000 MW units. The end of the US ban on trade in nuclearmaterial with China, in Spring 1998, could encourage thedevelopment of nuclear power in China.

In the medium term, four new plants are expected to be built, asshown in Table 15.11. Construction of the second phase of Qingshan,with two generators of Chinese design, started in June 1996.Qingshan Phase 3 will have two CANDU-6 pressurised heavy waterreactors; construction has started. The third plant is at Lingao, nearDaya Bay and will have two PWRs supplied by Framatome. Thefourth plant, will have two VVER-1000 reactors, supplied by Russia.


Table 15.11: Committed Nuclear Projects in China

Given that nuclear is a capital-intensive option - with costs aboutthree times more per kW than a Chinese-manufactured coal plant -and that long lead times are required to build a nuclear plant, it isassumed in the BAU projection that nuclear capacity in China will be11 GW in 2010 and 20 GW in 2020.

China has abundant renewable energy resources. Thedevelopment of alternative energy technologies can be economic insome areas, particularly in remote, off-grid locations. Renewableenergy development is given priority in many provinces and is oftenincluded in rural electrification programmes.

Wind power has the largest potential to contribute to electricitysupply, and its development has been given priority by the Chinesegovernment. Small wind turbines are already manufactureddomestically. China’s wind resource potential exceeds 250 GW; siteswhere wind speed is high and which therefore are suitable forexploitation, are located in the coastal areas and islands off south-eastern China and in north-west China and inner Mongolia. In thecoastal areas, where demand is growing fast, medium- to large-scalegenerators could be developed that would generate electricity inparallel with diesel engines. In the northwest, where populationdensity is low, the emphasis is more on domestic use of small-scalewind turbines.

Grid-connected capacity in 1994 was 32 MW; in 1997 it hadreached 217 MW. At the end of 1994, there were more than 140 000small-scale wind turbines (50 to 50 000 W) with a capacity of 17 MW.There are two different estimates of how much wind power capacitywill be installed in the short to medium term: the State PlanningCommission calls for 400 to 500 MW by 2000 and 1000 to 1100MW by 2010. The Ministry of Power targets 1000 MW by 2000 and3000 MW by 2010. It is assumed in the BAU projection that wind

Plant Name / Location Capacity (MW)

Qingshan - Phase 2 2 x 600

Lingao 2 x 1000

Qingshan - Phase 3 2 x 700

Lianyungang 2 x 1000


capacity in China will increase to 2 GW in 2010 and 4 GW in 2020.Photovoltaic cells are used to provide electricity for isolated areas.

Current PV capacity (off-grid) is 5 MW. There are a number of plans forfurther use of off-grid PV, and the government plans an additional30MW by 2000. There are areas with high-temperature geothermalpotential in Tibet, Yunnan and Sichuan, with a theoretical resourcepotential of 6.7 GW. However, the majority of this potential is in thesparsely populated area of Tibet, so large expansion of geothermal isunlikely. Geothermal capacity at the end of 1994 was 30 MW. Biomassis used in small-scale applications. There is potential for using bagassefor power generation by the sugar industry in south-coastal regions.

As with other developing countries, there is much uncertaintyabout funding to finance new power projects. New growth in capacityis expected to be financed both by local and by foreign investment.This can be achieved by introducing wholly-foreign-owned plants, byraising funds through international financial organisations, by foreigngovernment loans and by Chinese and foreign joint ventures. Foreigninvestment in China’s power sector is now about 10% of the total andthe government seeks to increase that to 20%. China’s first privatesector Build-Operate-Transfer (BOT) project was the Guangxi LaibinB Plant. Foreign investment projects, however, are often faced withdifficulties, such as difficult bureaucracy or insufficient rates of return.

CoalChina’s coal resources are variously estimated at 1-4 trillion

tonnes, second in the world to Russian resources. China has 115billion tonnes of proven reserves, a figure which places China third inthe world after the US and Russia, with about 11% of world reserves.While China’s overall reserves are large, the proportion of them to adepth of 150 metres is relatively small. The bulk of reserves availableover a 20-year time period at present rates of production, are locatedat depths of 150 to 300 metres, and between 300 and 600 metresbeyond that period. Most of these reserves are located in relativelyremote areas in the north-central part of eastern China, especially inShaanxi, Shanxi, Henan and Shandong provinces.

China is the world’s largest producer of coal and the percentagecontribution of China to world production has been growing steadily.In 1996, total Chinese production reached around 1.4 billion tonnes,and accounted for 37% of total world production. This representsmore than a doubling of the 620 million tonnes produced in 1980.


The pattern of coal production in China has altered significantly overthe last 40 years. The north and east of the main coal belt wereformerly the main production areas, but the focus is now on the coalfields of Shanxi, Shaanxi and Inner Mongolia.

Chinese coal exports were about 29 million tonnes in 1996,representing some 6% of total world coal exports. The north Asianregion is the principal market for Chinese coal, with Japan and Koreaeach receiving about one-quarter of total exports. China and Japanhave a long-term trade agreement for the export of steam and cokingcoal. Chinese coal exports are 2% of total Chinese coal production.

As the world’s largest producer and already a significant exporter,China’s performance could have implications for the world market,depending on future trends in domestic production, imports andexports. There are many features about the Chinese coal industrywhich differ from that of any other major player. The level ofuncertainty about China’s future role in world markets is heightenedby the role the government plays in the Chinese industry. It is hard topredict the outcome of policies designed to achieve non-commercialobjectives such as self-sufficiency and regional development. China’strade position will depend on the balance between internal demandand supply - the country could turn out to be either a net importer ora net exporter. There may be government pressure to earn foreignexchange from coal exports by encouraging coal production orlimiting its domestic consumption. The overriding determinant of theoutcome will be the extent to which China embraces market principlesin the management of its coal industry and whether the industryremains under state or municipality control or private participation isprogressively involved. It is assumed in this Outlook that, whileChina’s export capacity could increase from the current level, thestrong domestic pressures on demand and the already overburdenedtransportation system are unlikely to allow Chinese net exports to risesubstantially above present levels.

OilChina has only recently become a major oil producer, with

production increasing from around 0.5 million barrels per day in 1970to 3.2 million barrels per day in 1997. Almost 90% of China’s oil isproduced onshore. Nearly one third of it comes from the Daqinq fieldwhich currently produces slightly more than 1 million barrels a day.While there are many prospective and unexplored areas in China, the


longer-term oil production outlook depends to a large extent on thegeologic potential and the timing of development of the remote Tarimbasin. The potential of this basin has been recognised for some time,but its exploration and development have been slow. Estimates ofpotential reserves in the Tarim basin vary from as little as a few billionbarrels to upwards of 80 billion barrels. However, the initialexperiences of foreign oil companies in the Tarim basin have not beenvery encouraging.

Chinese reserve estimates are extremely uncertain in general. Asdiscussed in Chapter 7, the oil supply projections in this Outlook arebased on remaining discovered reserves of 29.5 billion barrels. Thismatches a conservative view of the development of Chinese oilproduction. Production grows till around 2010 and then declines toabout 2 million barrels per day by 2020.

Figure 15.7 compares expected oil production and demand. Thegap between domestic production and demand widens, especially after2010. It is projected that China will be importing more than 8 millionbarrels a day by 2020, making it a major importer in the world oilmarkets. In comparison, projected net imports of the OECD Pacificregion by 2020 are 7.6 million barrels per day.

Figure 15.7: Domestic Supply and Net Oil Imports in China

-2

0

2

4

6

8

10

12

1975 1980 1990 1993 1995 1996 2010 2020

Mbd

Net imports Supply


GasWhile natural gas production in China grew strongly throughout the

1960s and 1970s with the discovery of large fields in the Sichuanprovince, it remains a marginal fuel within the Chinese energy system as itis mostly used as a feedstock for the fertiliser industry. In recent years, gashas suffered from production cutbacks, and current production levels arelow relative to the potential reserves base. The current Five Year Planforesees an annual production target of 25 billion cubic metres of naturalgas by 2000 and close to 30 billion cubic metres by 2005.

Biomass

Current Patterns of Biomass Energy UseEstimates of China’s current biomass energy consumption vary

greatly, ranging from approximately 170 to 280 Mtoe. For thepurposes of this report, an average estimate of 206 Mtoe wascalculated as an average of the most reliable sources. This implies that,in 1995, biomass accounted for 19% of China’s primary energyconsumption, 24% of total final energy consumption, 28% of totalenergy in stationary uses, and approximately 60 to 70% of ruralhousehold energy use.

China’s total biomass use (in absolute terms) is the highest in theworld, accounting for 20% of the world’s biomass primary energysupply and 36% of that of Asia. There are around 800 million peopleand half a million rural enterprises using biomass energy11.

Virtually all biomass energy in China is used in rural areas, whereapproximately 70% of the population lives12. The rural sector includesrural households, agricultural activities and town and villageenterprises (TVEs). No data are available on the shares of end-uses ofbiomass, but it can reasonably be assumed that the major portion ofbiomass is used in households. It is often difficult to separatehousehold uses (cooking, water and space heating) from agriculturaluses (like cooking of pig feeds). Data for biomass used in TVEs are

11. Rural Energy Resources: Applications and Consumption in China, Fang Zhen, China Center forRural Technology Development, State Science and Technology Commission, Energy Sources,Vol.16, 1994.12. According to a 1989 study, in 1985, the share of biomass in total energy consumption byurban households was only 1%, while it was 79% in the rural household sector (REDP, SectoralEnergy Demand in China, REDP/UNESCAP/UNDP/GOC/GOF, 1989). The major fuel inurban households is coal, which is also the second most used fuel in rural households.


unavailable, but it has been estimated to amount to less than 10% ofhousehold biomass fuel use13.

Regional differences in total rural energy use, and thus in biomassenergy use, are significant. In the northern parts of the country,heating requirements are substantial and may involve as much fuel useas cooking. In the southern and central areas, cooking of pig feed inrural homes is a major use of energy, often accounting for a largershare of energy use than the preparation of family meals.

Fuelwood and agricultural residues (straw and stalks) eachaccount for roughly half of total biomass energy use. At present, mostbiomass is directly burned in low-efficiency energy devices. There isno charcoal production, mainly because of the availability andextensive use of coal briquettes in the household sector.

Past TrendsChina’s rural areas have undergone substantial change since

market reforms were initiated in the late 1970s. In most areas, the1980s marked a major shift away from subsistence farming towards amore commercialised and industrialised rural economy, which in turnled to significant changes in the rural energy mix. The exactmagnitude of these changes is difficult to judge due to the lack ofconsistent data series. According to figures published by the Ministryof Agriculture, between 1979 and 1989 biomass energy use increasedby 24% in absolute terms. However, its share in total rural energydeclined from 72% in 1979 to 51% in 1989. Another sourceindicates that in 1995 this share had further declined to 29%14.

The major reason for these changes has been the rapiddevelopment of town and village enterprises, which use mainlyconventional fuels. The share of conventional energy used byhouseholds also increased from 14% in 1979 to 20% in 1989, and itcan be assumed that this trend has continued in the early 1990s15.Surveys indicate that higher rural incomes have meant moresophisticated demands for energy services, with a gradual shift to

13. e.g. for tea and tobacco drying, for pottery firing and heating hothouses. ESMAP, Energy forRural Development in China: An Assessment Based on a joint Chinese/ESMAP Study in Six Counties,Report No. 183/96, World Bank, 1996.14. Cui Shuhong, Biomass Energy for Rural Development in China, in IEA, Biomass Energy: Data,Analysis and Trends, Workshop Proceeding, forthcoming.15. Cui Shuhong gives a figure of 39% in 1995.


higher-quality fuels and more efficient and convenient devices. Inmost cases, this implies a substitution of biomass fuels by conventionalfuels, mainly coal16.

ProjectionsIt is expected that observed past trends in biomass energy use will

continue over the Outlook period. Although there are substantialprogrammes aimed at promoting the efficient and sustainable use ofbiomass17, the ongoing shift to higher-quality fuels resulting fromincreasing per capita incomes, combined with the adoption of moreefficient firewood stoves, will most likely result in a decline of averageper capita biomass use, from 170 kgoe per person now to approximately150 kgoe in 2020. However, due to population growth, the totalamount of biomass consumed is expected to increase, from 206 Mtoe in1995 to 224 Mtoe in 2020. This represents a small annual growth rateof 0.3% on average, compared with 3.6% for conventional primaryenergy fuels. As a result, the share of biomass in total primary demandis projected to decline from 19% in 1995 to 10% in 2020. Figure 15.8below summarises the biomass projections for China. The assumptionsand methodologies are given in Chapter 10.

Including biomass in the total energy picture has manyimplications for energy analysis. Not only will the level of energyintensity be affected, but so also will its overall trend. Since biomass isgenerally used in a very inefficient way, the substitution of biomass byconventional fuels will result in a gain of overall energy efficiency. Inthe case of China, this is reflected in a more rapidly decreasing energyintensity curve. The inclusion of biomass gives a more realistic pictureof actual energy demand and energy mix, allowing more realistic andeffective policy decisions.

16. Consumer preferences are complex; in some areas, they prefer to use coal briquettes, instead offirewood or straw, if they can afford them. However, in other relatively wealthy areas, such as inthe southern Jiangsu province, farmers still prefer to use straw for cooking, partly because of itsrelative speed and ease of ignition compared with briquettes.17. Such as the on-going promotion of biogas digesters, the development of new fuelwoodplantations to overcome local fuelwood shortages and the dissemination of more-efficient cookingstoves.


Figure 15.8: Total Primary Energy Supply including Biomass,1995-2020

0

500

1000

1500

2000

2500

1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent

Biomass Conventional energy


Chapter 16 - East Asia 299

CHAPTER 16EAST ASIA

IntroductionEast Asia1 is of particular importance for the evolution of

long-term global energy demand because of the region’s rapideconomic growth. It includes the maturing industrial economies of theRepublic of Korea, Chinese Taipei and Singapore, as well as countriessuch as Malaysia, Thailand and Indonesia that are continuing aprocess of economic development and greater integration with theworld economy, and countries such as Vietnam that are on thethreshold of development. The region’s GDP growth rate has averaged7% over the last three decades, higher than any other region. Theaverage, however, disguises particularly high rates of growth in someof the best performing countries, especially over the last 5 to 10 years.For example, the Republic of Korea’s, annual growth exceeded 8%between 1980 and 1995. In Thailand, it was 10% between 1985 and1995. As a result, per capita incomes in some of the more advancedEast Asian economies, such as Singapore and Chinese Taipei, are nowcomparable with those in some OECD countries.

Most of the countries in the region have taken steps to liberalisetheir economies, including measures to open foreign trade andimprove investment regimes, reduce subsidies and fiscal deficits,privatise state enterprises and control inflation. While some countriesbegan the process more than a decade ago, others have undertaken itonly recently. The general result has been increased competition andefficiency, although the recent financial crisis has raised questionsabout the allocation of capital. Much of the impetus to growth in EastAsia has come from the development of a broadly based and export-oriented industrial sector. The share of industry in GDP has increased

1. East Asia includes the following countries: Brunei, Indonesia, Malaysia, Myanmar, NorthKorea, Philippines, Singapore, the Republic of Korea, Chinese Taipei, Thailand, Vietnam,Afghanistan, Bhutan, Fiji, French Polynesia, Kiribati, Maldives, New Caledonia, Papua NewGuinea, Samoa, Solomon Islands, and Vanuatu. Please note that the following Asia and Oceaniacountries have not been considered due to lack of data: American Samoa, Cambodia, ChristmasIsland, Cook Islands, Laos, Macau, Mongolia, Nauru, Niue, Pacific Islands (US Trust), EastTimor, Tonga and Wake Island.


substantially across the region, approaching 40% in some of the moredeveloped economies, while that of agriculture has declined. In thosecountries where industrialisation commenced earliest and has beendeepest - the Republic of Korea, Chinese Taipei, and Singapore - acombination of rising wages and tight labour markets has driven thetransition from labour-intensive manufacturing to activities withhigher value added and higher levels of capital and technology. Inother countries, such as Malaysia and Thailand, the manufacturingsector is still largely based on labour or material resources, but similarpressures will be felt there in time, leading to changes in thecomposition of the region’s production and trade.

Figure 16.1: Average GDP Growth and 1995 GDP Per Capita

A key uncertainty in the projections presented in this Outlook isthe future sustainability of such high economic performance. Therecent financial crisis in the region casts shadows over future economicgrowth, at least in the short- to medium-term.

0

1

2

3

4

5

6

7

8

9

10

Republicof Korea

Singapore Malaysia Philippines

%

0

5000

10000

15000

20000

25000

30000$

1960-70 1970-80 1980-90 1990-95 GDP per capita (1995) (right side scale)

Indonesia AggregateThailandChineseTaipei


Table 16.1: Economic and Population Data for Selected East AsianCountries

Table 16.2: Energy Demand in Selected East Asian Countries,1995 (Mtoe)

Box 16.1: Asian Financial Crisis

The severe pressures on foreign exchange markets in many EastAsian countries in late 1997 have accentuated internal financialstrains and contractionary pressures on economic activity. Thecrisis has been largely contained, till now, and most of thecurrencies have regained some of the ground lost during the crisis.But interest rates remain high compared with a year ago and mostequity markets are still depressed. Adverse terms of trade, declinesin private sector net worth, increases in the cost of capital, and, in

GDP Population GDP per Capita

1995 Growth Rates 1995 Growth Rates 1995($ Billion 1990 (1985-95) (millions) (1985-95) ($ 1000 1990 and

and PPP) (annual, %) (annual, %) PPP per capita)

Republic of Korea 507 8.8 45 0.9 11.3Indonesia 677 7.4 193 1.7 3.5Chinese Taipei 337 7.9 21 1.1 15.8Thailand 380 9.4 58 1.3 6.5Malaysia 165 7.7 20 2.5 8.2Regional Total 2462 7.3 583 1.8 4.2

Total Primary Energy Supply Total Final ConsumptionTotal Coal Oil Gas Total Electricity

Republic of Korea 145 28 90 9 114 14Indonesia 86 6 42 35 48 4Chinese Taipei 65 17 33 4 44 9Thailand 52 7 35 10 37 6Malaysia 33 2 20 11 22 3Regional Total 464 84 264 76 316 42


the worst cases, major credit limitations are exerting powerfuldownward pressures on domestic demand. Banks are experiencingfinancial strains that are likely to worsen as the economicdownturns continue.

In the region as a whole, a marked slowdown in economicactivity is increasingly evident. The OECD Secretariat projectseconomic growth of 0.1% in 1998 for the group of Dynamic AsianEconomies (Indonesia, Hong Kong, Malaysia, the Philippines,Singapore and Chinese Taipei), compared to the 6.2% in 1996. Inthe Republic of Korea, the economy is expected to contract in1998 (-0.2%, compared to a 7.1% in 1996), reflecting a sharpdecline in domestic demand and investment.

The repercussions of the financial turmoil on the economies ofthe East Asian region will continue for some time yet. Theeconomic turndowns are likely to be severest in those countrieswhere currency depreciations have been greatest. In most of theseEast Asian countries, recovery may not begin before 1999, and itcould take longer in the most severe cases.

The impact of the financial difficulties in the East Asiancountries began to hit the energy markets, and particularly the oilmarket, toward the end of 1997 and carried over into the first halfof 1998. The impact on global oil demand is estimated to be onthe order of 500 thousand barrels per day in 19982. The pace ofeconomic recovery in the region will determine the future patternof oil demand in these countries.

In line with rapid economic growth, energy demand in the regionhas grown strongly over the past quarter century. Between 1971 and1995, total primary commercial energy demand increased at anaverage annual rate of 6.8%, very close to regional GDP growth.Energy demand more than quadrupled in absolute terms, from 96Mtoe to 464 Mtoe. This was a faster rate of growth than thatexperienced in any other region and resulted in East Asia’s share ofglobal energy demand increasing from 1.9% to 5.6%. Moreimportantly, the region accounted for about 11% of worldincremental energy demand. As shown in Table 16.2, the major energyconsumers in the region are the Republic of Korea, Indonesia andChinese Taipei, where the industrial sector has been the strongest.

2. Oil Market Report, IEA, July 1998.


Together, these three countries accounted for over half of East Asianenergy demand in 1995. Along with industrialisation, the shift fromnon-commercial to commercial energy sources, the development ofrural electrification and the growing demand for transport serviceshave been the chief motors driving growth in energy consumption.

As shown in Figure 16.2, oil is the dominant fuel in the totalprimary commercial energy supply of the region. Its share remainedbroadly constant since 1971. The absolute increase in East Asia’s oilconsumption accounted for about 24% of world incremental oildemand. Coal’s share halved, from 36% in 1971 to 18% in 1995.Natural gas was the fastest-growing source of primary energy over theperiod, although from a low base. This followed discoveries of largeindigenous gas reserves in some countries in the 1970s and thesubsequent development of LNG import infrastructure in others,principally the Republic of Korea and Chinese Taipei. The rapiddevelopment of the nuclear programme in these two countries also ledto an increase in the nuclear share of primary energy demand to 6% by1995. These figures refer only to commercial energy types. Non-commercial biomass plays an important role in the regional energysupply/demand balance.


The aggregate commercial energy intensity of the region hasdeclined slightly in the last two decades. This trend is dominated by thetwo largest economies, the Republic of Korea and Chinese Taipei. Inmost other countries, intensities have actually increased. This slight fall

Solid Fuels 18%

Renewables 1%Hydro 1%

Nuclear 6%

Gas16%

Oil57%

Solid Fuels 17%

Renewables3%

Hydro 1%

Nuclear 5%

Gas23%

Oil50%

1995 2020

464 Mtoe 1275 Mtoe


in energy intensity has been achieved against a background of rapidindustrialisation and rising per capita incomes. In the higher incomeeconomies, structural change has also favoured the services sector which,except for its transport component, lowers national energy intensities. Inthe Republic of Korea and Chinese Taipei, there has been a downwardtrend in the energy intensity in the iron & steel and chemical industries,which together account for almost 60% of industrial energy demand.When non-commercial biomass use is included, the declines in energyintensity experienced over the recent past become more pronouncedthan those calculated on the basis of commercial energy alone.

In the BAU projection, GDP is assumed to grow significantlyslower than over the preceding two decades. As shown in Table 16.3,East Asian economic growth of 4.5% is assumed, compared with 7% inthe past three decades. The assumed slowdown reflects the maturing ofthe larger economies in the region and the impact of the Asian financialcrisis. The population growth rate is also assumed to slow from itspresent level to an average of 1.2% between 1995 and 2020. Together,the population and economic growth assumptions imply that there willcontinue to be substantial increases in incomes in the region, averaging3.3% per year to 2020. On this basis, regional per capita income wouldbe about $ 9500 (at 1990 prices and PPP) by the end of the forecastperiod. As for energy prices, historical series on fuel types in mostcountries of the region is unavailable or poor. International trends are,therefore, taken as proxies for the growth of end-use prices in theregion. Prices for oil products are assumed to follow international crudeoil prices. Similary, the coal price follows assumed international pricesand the LNG price follows the Japanese LNG import price.

Table 16.3: Economic Assumptions

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal Price ($1990 per metric ton) 44 40 42 46 0.5%Oil Price ($1990 per barrel) 6 15 17 25 2.1%LNG Price ($1990 per toe) n.a. 126 141 210 2.1%GDP ($Billion 1990 and PPP) 499 2462 4879 7404 4.5%Population (millions) 360 583 710 778 1.2%GDP per Capita ($1000 1990 and 1.4 4.2 6.9 9.5 3.3%PPP per person)


Energy Demand OutlookTotal primary commercial energy demand in East Asia in the

business as usual projection grows at an average annual rate of 4.1%to reach 1275 Mtoe in 2020 (see Table 16.4). This implies that EastAsia will account for about 15% of world incremental commercialenergy demand over the Outlook period. The trends in primary fuelshares differ from those over the past twenty years and reflect effortsby some countries to reduce dependence on imported oil. As aconsequence, coal’s share of primary demand, which had declinedsince 1971, is expected to remain fairly constant to 2020, at about17%. Although oil is expected to decline in importance, it willremain by far the most important fuel source, accounting for overhalf of total primary energy demand in 2020. At 375 Mtoe,incremental oil demand in East Asia is expected to be larger than inany other region and is expected to be one of the major forces drivingworld oil demand. Reflecting the development of the region’sresources, natural gas is also expected to play a more important role inthe energy balance, increasing its present share of primary energydemand from 16% to 23% in 2020. Gas will be favoured for itsability to substitute for oil in a range of uses, as well as for itsenvironmental characteristics. The shares of nuclear and hydropowerare likely to remain constant.


As shown in Table 16.5, total final consumption is expected toincrease at 3.8% per annum. Gas is expected to register substantialgrowth of 5.4%. Electricity demand is projected to grow at about 5%,

1971 1995 2010 2020 1995-2020Annual

Growth Rate



higher than the assumed GDP growth rate. Solid fuels are expected tolose significant market share, mainly as a result of inter-fuelsubstitution in the stationary sectors.



Stationary SectorsDemand for energy in stationary uses is projected to increase by

2.8% per year. This growth is expected to slow down, as shown inFigure 16.3, mainly due to changes in industrial structure. Althoughgrowth in industrial output is expected to continue strongly, itscontribution to GDP is likely to decline as the larger economies in theregion become increasingly service-oriented. In addition, within theindustrial sector, a trend towards less energy-intensive subsectors isexpected as the skill and wage base of the region continues to rise,favouring the development of higher-value-added industries.Nevertheless, the iron & steel and chemical industries will remain animportant source of growth in industrial energy demand. The increasein energy demand in the residential and commercial sectors will bestronger than that in the industrial sector. Two major factorscontributing to this trend are increases in income and substitution ofcommercial fuels for non-commercial biomass. As for the fuel mix, gasis projected to increase at 5.4% per annum, overtaking solid fuels bythe end of the Outlook period. The bulk of the increase in gas demandis projected to come from the industrial sector. In the residential andcommercial sectors, gas penetration is likely to remain low in a large

1971 1995 2010 2020 1995-2020Annual

Growth Rate

TFC 79 316 577 813 3.8%Solid Fuels 30 47 54 57 0.8%Oil 42 208 388 543 3.9%Gas 1 19 45 71 5.4%Electricity 5 42 90 141 4.9%


part of the region where the demand for space heating and hot wateris limited due to a year round mild climate.



MobilityAs shown in Figure 16.4, demand for mobility in East Asia is

projected to increase in line with rising incomes. With a growth rate ofalmost 5%, mobility demand is expected to triple over the Outlook

0

50

100

150

200

250

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500

Gross Domestic Products ($ Billion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent

Solid Fuels Oil Gas

1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 55 179 282 359 2.8%Solid Fuels 30 47 54 57 0.8%Oil 24 113 183 231 2.9%Gas 1 19 45 71 5.4%


period. More importantly, demand for mobility is expected to accountfor about 65% of the growth in total final oil demand over the period.Its share in total primary oil supply is projected to increase from 36%in 1995 to 50% by 2020.



The reasons for growth in mobility demand include increasingeconomic activity, rising per capita incomes and the continuingprocess of urbanisation. Reflecting these factors, the growth in thevehicle fleet is expected to remain strong. As Figure 16.5 illustrates,

0

50

100

150

200

250

300

350

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500


mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 19 95 205 313 4.9%


despite growth in the recent past, passenger vehicle ownership is stillwell below that of Japan. Even allowing for possible impediments toexpansion, such as inadequate roads, congestion or governmentregulation, there remains a vast potential for expansion in vehicle fleetsin most countries.

Figure 16.5: Vehicle Ownership versus GDP per Capita

Source: World Road Statistics ’98, International Road Federation, 1998.

ElectricityElectricity demand in East Asia is projected to grow along with

GDP. It is expected to increase by close to 5% per year over theOutlook period, higher than the assumed GDP growth rate. As aresult, the current 13% share of electricity in total final commercialenergy consumption will reach 17% in 2020.


China

Republicof Korea Singapore

Chinese Taipei

Malaysia

ThailandIndiaPhilippines

Japan

Indonesia

0 5 10 15 20 25 300

100

200

300

400

per capita GDP ($ 1000 at 1990 prices and PPP per person)

Number of Passenger Vehicles (per 1000 Inhabitants)

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 5 42 90 141 4.9%



Although this expected growth appears to be strong, it is wellbelow the 9% annual increase in the 1970s and 1980s. The slowdownreflects, in part, the substantial increase in electrification rates in theindustrial, commercial and household sectors, as well as the assumedslower rate of GDP growth.

Table 16.9: Electricity Sales per Capita and per Customerin Indonesia (kWh)

Source: Statistik dan Informasi Ketenagalistrikan dan Energi 1995/1996, Direktorat Jenderal Listrikdan Pengembangan Energi, Jakarta 1996.

0

20

40

60

80

100

120

140

160

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500

mill

ion

tonn

es o

il eq

uiva

lent

Gross Domestic Products ($ Billion at 1990 prices and Purchasing Power Parities)

1971 - 1995

1996 - 2020

kWh per person kWh per customer

1975/76 21 24571980/81 44 23761985/86 76 21241990/91 158 24681991/92 172 25391992/93 188 25931993/94 205 25701994/95 231 25491995/96 261 2536


As Table 16.9 shows, per capita electricity sales in Indonesiaincreased rapidly in the period 1975 to 1995, as a result of increasingelectrification, but consumption per customer has remained broadlyunchanged. Consumption per industrial customer has beenincreasing, but not consumption per residential customer.

Supply

Power GenerationThe region includes a large number of countries with different

fuel mixes and significant differences in electricity consumption.Nuclear power is the most significant source of electricity in theRepublic of Korea; Singapore’s electricity generation is based on oil;Vietnam relies almost exclusively on hydropower; Thailand, Malaysia,Indonesia and Chinese Taipei use a mix of coal, oil, gas andhydropower. Singapore and Chinese Taipei are close to OECD levelsof per capita electricity consumption, whereas other countries, likeVietnam and Indonesia, have some of the world’s lowest levels. Fourcountries, the Republic of Korea, Chinese Taipei, Thailand andIndonesia, produce three quarters of electricity generated in theregion.

Table 16.10: Per Capita Income and per Capita Electricity Generationin East Asian Countries, 1995

Despite the current Asian economic crisis, electricity generation inEast Asia is projected to grow substantially over the Outlook period, at4.9% a year. Most of the growth in electricity generation is expected tocome from coal- and gas-fired plants, with coal increasing at 6.7% perannum and gas at 7.3%. Both fuels increase their shares in the electricity

Country $ 1990 and PPP per person kWh per person

Singapore 26180 7384Chinese Taipei 15807 5769Republic of Korea 11298 4117Malaysia 8168 2257Thailand 6522 1375Indonesia 3501 317


generation mix, from 23% for coal and 17% for gas in 1995 to 35%and 30% respectively in 2020. Increased use of gas would requireexpansion of gas pipelines or LNG infrastructure. These may be delayedbecause of lack of funding as well as lower demand expectations causedby the recent economic crisis. Coal plants may be preferred if gas isunavailable or if indigenous supplies are reserved for export.

Table 16.11: Electricity Generation in East Asia (TWh)

In 1971, oil accounted for more than half of electricity output,followed by hydropower. Since then, other sources have beendeveloped. In 1995, oil-fired generation accounted for 29% of totaloutput and that share is projected to decline further as policies todiversify away from oil continue across the region. By 2020, oil isprojected to account for 10% of the generation mix; in absolute terms,electricity generated from oil is projected to increase from 175 TWh in1995 to 210 TWh in 2020. Use of diesel-fired engines could continuein remote regions. This is, for example, the case in Indonesia whereregions outside the interconnected system of Java-Bali rely on dieselengines for their electricity needs. Some customers connected to thegrid also rely on their own diesel generators rather than on theunreliable supply from the national utility. Some of the new CCGTplants in East Asian countries are expected to run on oil and gas or, onoil until gas supplies become available. Chinese Taipei is planning toadd some orimulsion-fired capacity.

Electricity generation from nuclear power accounted for 17% oftotal output in 1995. The Republic of Korea started generatingelectricity from nuclear power in 1978, when the first nuclear reactorbecame operational, KORI-1, a 564 MW PWR. The Republic ofKorea now has 12 reactors (10 PWRs and 2 PHWRs) with an installed

1995 2010 2020

Solid Fuels 140 377 705Oil 175 223 210Gas 105 324 614Nuclear 102 205 267Hydro 78 131 185Renewables 8 34 49Total 608 1294 2030


capacity of around 10 GW. The most recent unit, Wol Sung 2, startedcommercial operation in July 1997. Nuclear is the largest single sourceof electricity in The Republic of Korea; in 1995 it accounted for 36%of electricity generation.

Nuclear power also accounts for about a third of electricityoutput in Chinese Taipei which had an installed capacity of 5 GW in1995. The country plans to increase its nuclear capacity, althoughsome opposition exists.

The Philippines built a nuclear plant in 1985, but the fuel for itwas never loaded following controversy over the circumstances of itsconstruction and concerns over its safety. The 620 MW Bataan plantis now mothballed. There have been discussions to convert it to aCCGT plant.

Other countries in the region, such as Indonesia, Thailand andVietnam (and North Korea) have stated their intention to buildnuclear plants, but it is assumed in this Outlook that no nuclear plantswill be built in countries in the region outside the Republic of Koreaand Chinese Taipei. Nuclear capacity in the region increases to 37 GWby 2020. The share of nuclear in the output mix is projected to fall to9% by the end of the projection period.

Table 16.12: Nuclear Plants under Construction in the Republic of Korea

Source: KEPCO.

Hydropower accounts for 13% of the region’s electricitygeneration. This share is projected to fall to 9% by the end of theOutlook period. East Asia has significant untapped hydro resources;the Mekong River basin alone could provide 150-180 TWh a year3.Many of the sites are located in remote and undeveloped areas thatrequire the construction of long transmission lines.

Plant Unit Reactor Type Capacity (MW)

Yonug Gwang Unit 5 PWR 1000Unit 6 PWR 1000

Wol Sung Unit 3 PHWR 700Unit 4 PHWR 700

Ul Chin Unit 3 PWR 1000Unit 4 PWR 1000

3. Thailand Fuel Option Study, World Bank, Washington, DC, 1993.


A number of hydro projects are being developed in the region,and governments are trying to encourage private sector participation.By 2020, hydropower capacity could increase from 25 GW at presentto around 55 GW. Many of the new projects are faced with financial,environmental and social difficulties. The most controversial of theseprojects is Malaysia’s 2400 MW Bakun dam in the remote Sarawakregion. The Nam Theun 2 dam project in Laos, along with a numberof other hydro projects in Thailand, also faces difficulties.

The most significant non-hydro renewable resources in the region isgeothermal energy, concentrated in the Philippines and Indonesia. In1995, East Asia accounted for 20% of world geothermal electricitygeneration. The Philippines was the world’s second largest producer ofgeothermal energy, after the US, with an output of 5809 GWh in 1995.Indonesia accounted for 27% of geothermal electricity in East Asia, or2175 TWh. There are several projects, particularly in Indonesia, to increasegeothermal capacity, but they could be delayed as a result of the finacialcrisis. Geothermal capacity in the region is assumed to increase from 1.4GW in 1995 to 8.8 GW by the end of the Outlook. Other renewables arealso assumed to increase, but additions are likely to be small.

Co-generation is also encouraged by governments in some of thecountries, including The Republic of Korea, Thailand, Chinese Taipeiand the Philippines. There is insufficient data on which to estimatepresent or future co-generation capacity.

Table 16.13: Fuel Use in Power Stations and as a Share of TPES

Fuel consumption for power generation is projected to increase at4.8% per annum, which is slightly lower than the projected growth inelectricity output due to improvements in the efficiency of fossil-fueled power stations. Most improvements will come from the use of

1995 2020Mtoe % of TPES Mtoe % of TPES

Solid Fuels 34 7 157 12Oil 35 8 43 3Gas 27 6 109 9Nuclear 27 6 70 5Hydro 7 1 16 1Renewables 7 1 42 3Total 136 29 436 34


efficient combined cycle plants. Several utilities also plan to upgradetheir existing plant.

The power generation sector is projected to account for 34% oftotal primary energy supply in 2020, compared with 29% in 1995.Both coal and gas increase their shares substantially.

To meet rising electricity demand, power-generating capacity inthe region would need to increase from 126 GW in 1995 to 432 GWby 2020, requiring substantial investment. Following the financialcrisis and the resulting currency depreciations, power plantequipment, most of it imported, and fuel imports have become moreexpensive. Most of the countries in the region have opened theirpower sectors to private investors. However, until confidence returnsand the new higher prices have been passed to customers, independentpower producers may be reluctant to invest in Asian markets. Thisreluctance could affect capacity construction in the region.

OilEast Asia includes significant oil exporters, such as Indonesia and

Malaysia, and large oil importers like the Republic of Korea, Thailandand Chinese Taipei. In total, the region relies on imported oil to meetrapidly increasing demand.

Indonesia is the largest oil producer in the region. Its existingfields are mature and have complex geology characterised by small,highly porous structures, which results in rapid depletion. Indonesiaproduced about 1.4 million barrels a day in 1997 and seems to havemodest growth potential. However, the increasing use of enhanced oilrecovery techniques (EOR) such as steam-flooding and water-floodingis expected to keep Indonesian production stable in the medium term.By 2000, the majority of Indonesian output is expected to be EOR-based; as recently as 1994, the figure was only 30%. However, in thelonger term, production seems likely to decline.

The second largest oil producer in East Asia is Malaysia, whichproduced about 0.75 million barrels of oil a day in 1997, almost allcoming from offshore wells. Malaysian production is likely to remainflat in the medium term, as incremental output from new and satellitefields offsets declines from the main mature fields. After 2005,however, decreasing supply from the mature fields may start to pulloverall output down. Due to fast growing domestic demand, about 0.5million barrels a day in 1997, Malaysia’s status as an exporter lookslikely to be threatened in the near future.


Vietnam, Brunei and Papua New Guinea are three smaller oilproducers. With a proven oil reserves level of 600 million barrels,Vietnam currently produces close to 200000 barrels a day of oil,almost exclusively from offshore fields. Brunei supplies about 175 000barrels a day while output from Papua New Guinea is around 120000barrels a day. Production in Vietnam and Papua New Guinea is likelyto grow modestly in the short to medium term, while Brunei supply isanticipated to remain stable through the medium term.

The sluggish oil supply prospects of the region, compared withrapidly increasing demand, suggests that the projected increase will bemet by increasing imports.

Table 16.14: East Asia Oil Balance (Mbd)

CoalIndonesia is the only large coal producer in the region, its

production rising from 0.3 Mt in 1980, to about 45 Mt in 1996.Factors influencing growth have been large reserves of good qualitycoal, proximity to markets, high labour productivity and low labourcost, and Government policies that encourage foreign investment inthe industry.

Indonesian coal production rose by a massive 27% in 1995, and9.5% in 1996. Exports have continued to rise rapidly (by 26% in1994, 23% in 1995 and 16% in 1996). Total exports reached 37 Mtin 1996. Japan, Chinese Taipei and the Republic of Korea were themain destinations. Production capacity appears to be sufficient tomeet both export demand and expanding domestic demand.

Principal impediments to the expansion of Indonesian coaloutput arise from infrastructure costs incurred in developing remotesources. Export surpluses may be reduced as domestic demand forelectricity rises after 1997. For the rest of this decade, costs areunlikely to increase significantly, because conditions for newproduction are expected to be favourable and mining equipment andmethods should remain much as before. After 2000, supply costs will

1996 2010 2020

Total Demand (incl. bunkers) 6.2 10.1 13.7All Supply 2.9 2.1 1.7Imports 3.3 8.0 11.9


be influenced by geological mining conditions, mining methods andequipment, labour rates and infrastructure capacities.

GasOne of the main features of the Outlook for East Asia is the

increasing role that natural gas is expected to play in the region, bothin final demand and in power generation. The development andincreased utilisation of gas require a degree of planning and co-ordination not necessary with other fuel supplies. In East Asia, gasdevelopment requires the construction of dedicated transport anddistribution facilities, a readily available market and the negotiation ofprices for individual markets. Many current gas projects in the regionconsist of a single supply source (often one field), tied by pipelines toa single demand centre (often a power plant). This pattern will changeas the regional market for gas matures and an interconnected pipelinesystem is developed, linking multiple supply sources with multiplecentres of demand. At the current stage of development, large up-frontinvestments in production and distribution infrastructure are requiredif gas is to increase its share in total energy demand to the extentimplied in the projections presented here.

The three largest producers, Malaysia, Indonesia and Vietnam,together account for about 3250 billion cubic metres of provenreserves, with a further 350 billion cubic metres in Brunei andThailand. Papua New Guinea is also expected to provide increased gasresources over the outlook period. Based on current productiontrends, East Asia has a reserves-to-production ratio of 66 years4 .

On the demand side, gas is expected to play the most importantrole in countries with indigenous resources, such as Indonesia,Malaysia and Thailand. These countries have pipeline networks thatcould form the backbone of a future regional gas transmission system.Total pipelines built so far reach about 5500 km; those currently inprogress and planned could add a further 5800 km5. However,countries with little or no gas resources, such as the Republic of Koreaand Chinese Taipei, also have plans to increase their gas utilisationthrough imports.

Much of the planned increase in gas utilisation in the region,especially in power generation, is expected to replace oil. So any

4. Asia Gas Study, IEA/OECD, 1996.5. Financial Times - Asia Gas Report, August 1997.


under-realisation of the projections presented in the current Outlookwill result in even higher demand for oil, and possibly coal. Theimplications for East Asia will be higher oil import dependence,especially on the Middle East, less potential for fuel diversificationand, hence, to strengthen energy security objectives, and increasedenvironmental costs.

Biomass

Current Patterns of Biomass Energy UseThe region’s final biomass consumption was estimated at

approximately 106 Mtoe in 1995, accounting for about 11% of theworld’s biomass consumption and 19% of total Asian biomass use.This implies a share of biomass in total final energy consumption of25% for the whole of East Asia, similar to that of China (24%) butmuch lower than that of South Asia (56%).

There are wide differences within the region. East Asia includescountries with very different levels of economic development andpatterns of energy use. It is therefore not surprising that biomassenergy use also varies significantly across the region, as shown in Table16.15.

Table 16.15: Final Biomass Energy Use in East Asia, 1995

The major biomass user is Indonesia, which consumes some 42%of the region’s supply. Vietnam, Thailand and the Philippines togetheraccount for another 40%. Myanmar is the largest consumer in relative

Final Share of Share of Per capitabiomass country in biomass energy use (kgoe)(Mtoe) the region in TFC Biomass Conv. fuels

Indonesia 43.9 42% 48% 227 251Vietnam 20.3 19% 75% 276 92Thailand 11.8 11% 24% 203 635Philippines 10.5 10% 45% 153 186Myanmar 8.6 8% 80% 191 47Malaysia 2.8 3% 11% 140 1103Others 7.8 7% - - -Total 105.7 100% 56% 193 154


terms (share of biomass in total energy use). As expected, the high-income countries of the region, the Republic of Korea, Chinese Taipei,Singapore and Brunei, consume little or no biomass energy. Theshares of biomass in total final energy consumption are stronglyrelated to development, modernisation and industrialisation,expressed by per capita levels of GDP and conventional energy use.The level of per capita biomass use is related to these variables and tothe availability of biomass resources. Countries with a higher share offorested land or higher production of certain crops have a higher levelof per capita biomass consumption.

Past TrendsMost countries of the region do not have satisfactory historical

data on biomass energy use. It is therefore difficult to assess pasttrends in biomass energy use and the pattern and pace of fuelsubstitution by conventional fuels. Data for the Republic of Koreashow a very rapid decline in biomass energy use during the period1971-95, reflecting the industrialisation and urbanisation of thecountry in that period. On the other hand, data for Thailand6 and thePhilippines7 show a steady increase in biomass energy use, both inabsolute and per capita terms. In the case of the Philippines, even theshare of biomass energy in total residential energy consumptionincreased between 1977 and 1989. In the case of Thailand, biomassshare in total final energy consumption declined from 69% in 1971 to55% in 1995 in the household and commercial sectors, and from 40%to 26% in the industrial sector.

ProjectionsEven though per capita biomass energy use is still increasing in

some countries, it is expected that for the region, overall averagebiomass use per capita will gradually decline over the Outlook period,due to further economic development and increasing urbanisation.Combined with expected population growth, this results in totalprimary biomass consumption increasing from 117 Mtoe in 1995to 136 Mtoe in 2020 (0.4% per annum). Given that primary

6. Thailand Energy Situation, Department of Energy Development and Promotion, Ministry ofScience, Technology and Environment, Bangkok, various years.7. Sectoral Energy Demand in the Philippines, Regional Energy Development Programme (REDP),United Nations, Bangkok, 1992.

consumption of conventional energy grows at 4.1% during the sameperiod, the share of biomass in total primary energy demand isprojected to decline from 20% in 1995 to 10% in 2020. Figure 16.7summarises the biomass projections for East Asia. Details regardingmethodology and assumptions can be found in chapter 10.

Including biomass in the energy mix has important consequencesfor energy indicators. As shown in Figure 16.8, it changes significantlythe level and inclination of the energy intensity curve, which decreasesmore rapidly if biomass is included, reflecting the gain in overallefficiency as biomass is pushed out by more efficient fuels.



0

200

400

600

800

1000

1200

1400

1600

1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent



140

160

180

200

220

240

260

280

1995 2000 2005 2010 2015 2020

toe/

$ 10

00 (1

990

pric

es a

nd P

PP)

Conventional energy only Including biomass

Figure 16.8: Energy Intensity with and without Biomass, 1995-2020


Chapter 17 - South Asia 323

CHAPTER 17SOUTH ASIA

IntroductionThe South Asian region includes India, Pakistan, Bangladesh, Sri

Lanka and Nepal. These countries are characterised by large andrapidly growing populations, with per capita incomes amongst thelowest in the world and poor social development indicators. As shownin Table 17.1, the region is dominated by India, which accounted for71% of GDP and 76% of the region’s population in 1995. The nexttwo largest economies are Pakistan and Bangladesh which contributed16% and 8% respectively of the region’s GDP.

In a global context, South Asia is of considerable importance,accounting for about one fifth of the world’s population, a share equalto that of China. Measured in purchasing power parities, the region hasa 4% share in world GDP and India is the fifth largest economy in theworld. In 1995, commercial energy consumption in the region reached284 Mtoe and has grown 6% per annum in the last two decades. In1995, South Asia accounted for 3.4% of world commercial energydemand, up from around 1.4% in 1971. As a result of these trends andthe dominance of coal in the region’s fuel mix, South Asia has alsobecome important in a global environmental context. IEA statistics1

indicate that India alone contributed 4% of world carbon emissions in1995 and the region as a whole almost 5%. With continuing growth ineconomic activity and energy demand, the region will become anincreasingly important element in global initiatives to reduce theenvironmental consequences of growing energy use.

Economic growth in the South Asian region averaged 4.6% in thelast two decades. India registered a high economic performance,especially since 1991, when its new economic reform program started.This new programme, which aims to move the country to a moremarket-driven system, led to average GDP growth of 6.5% in the last6 years. Other economies in the region are also implementingstructural and macroeconomic reforms. However, high population

1. CO2 Emissions from Fuel Combustion: 1972-1995, IEA/OECD Paris, 1997.


growth has reduced growth in per capita income levels. As Figure 17.1shows, South Asia’s per capita income was $1270 (1990 PPP) in 1995,which is substantially lower than the world average, and is the lowestof the 10 regions discussed in this Outlook. The net annual increaseof India’s population is more than 20 million persons. Currently,about three-quarters of the population resides in rural areas. Givenexisting trends, India is expected to overtake China, in terms ofpopulation, within the next three decades.

Table 17.1: South Asian Statistics

* CRW: Combustible Renewables and Waste.

Figure 17.1: GDP per Capita by Region

0

2

4

6

8

10

12

14

16

18

20

South Asia OECD China Other Regions

$ 10

00 a

t 199

0 pr

ices

and

PPP

per

per

son

GDP Population TPES (1995)

1995 Growth Rates 1995 Growth Rates excl. CRW* incl. CRW*($ Billion 1990 (1985-1995) (1985-1995)

and PPP) (annual, %) (millions) (annual, %) (Mtoe) (Mtoe)

India 1102 5.4 929 2.0 241 439Bangladesh 125 4.1 120 2.0 8 28Nepal 20 4.8 21 2.5 1 7Pakistan 253 5.2 130 3.1 32 51Sri Lanka 48 3.9 18 1.4 2 6


Accompanying the growth in the region’s economic activity havebeen substantial increases in energy consumption. Primarycommercial energy demand in South Asia grew at an average annualrate of about 6% between 1971 and 1995, to reach 284 Mtoe. Indiaalone accounted for 241 Mtoe, which ranked this country fifth in theworld in terms of primary energy demand. The rate of growth ofprimary energy demand in the region was well above that in OECDcountries and comparable to that of China, but did not match therates achieved in the dynamic economies of East Asia.

As for the fuel mix, the region’s commercial energy supply hasremained heavily based on coal. In 1995, coal accounted for 49% ofthe region’s total primary commercial energy demand, and oilcontributed a further 35%. The corresponding figures for India were57% and 33%. In South Asia and in India, these shares remainedclose to 1971 levels. The only significant development in the fuel mixin recent years has been the growing importance of natural gas; itsshare of regional energy supplies rose from 5% in 1971 to 12% in1995. This reflects important gas discoveries made in India, Pakistanand Bangladesh. These resources have been developed largely for use aspetrochemical feedstocks and in fertiliser production, but some arealso used in the power generation sector. Nuclear and hydropowerhave remained minor, although not unimportant, sources of energy inthe region, together accounting for around 4% of total primarycommercial energy demand in 1995. These figures refer only to thedemand for commercial energy and exclude the consumption of non-commercial biomass fuels. Biomass continues to meet a substantialproportion of the region’s energy demand, particularly in thehousehold sector. Non-commercial energy trends are discussed at theend of the chapter.

The commercial energy intensity (primary energy demand perunit of GDP) in the region has increased consistently at an averagerate of 1.2% per annum over the last two decades. This is one of thehighest intensity growth rates among the regions analysed in thisOutlook. Trends in intensity have been influenced by economicdevelopment factors and by the region’s fast population growth. Box17.1 discusses the energy-pricing environment and the issue ofsubsidies in the Indian energy market.



Box 17.1: Energy Pricing and Subsidies in the Indian Energy Sector

The energy industry in India is heavily regulated and energyprices are controlled by the government. The prices of mostenergy products are highly subsidised and set well below theireconomic costs. Direct subsidies are provided to certain fuels (suchas kerosene, diesel and LPG), and cross-subsidies exist betweenconsumer categories. Price distortions have accelerated thedepletion of domestic resources, discouraged foreign investment inthe energy sector and distorted the industrial and infrastructuraldevelopment of the country.

Retail prices for electricity are determined by the stategovernments on social and political grounds. The averageelectricity tariff is currently 80% of the cost of supply. Agriculturaland residential electricity users have both been subsidised. Initially,when the subsidy policy was devised, electricity demand in theagricultural sector was very small. Mainly because of the subsidisedtariff (13% of average generating cost), electricity demand in theagricultural sector grew rapidly. This sector now uses about 36% oftotal electricity.

Solid Fuels49%

Hydro/Other 3%Nuclear 1%

Gas12%

Oil35%

Solid Fuels43%

Hydro/Other 3%

Nuclear 1%

Gas20%

Oil34%

1995 2020

284 Mtoe 811 Mtoe


Table 17.2: Comparison of Average Electricity Retail Priceand Supply Cost in India

Note: 1 rupee (Rs.) = 100 paises. Source: Annual Report on the Working of State Electricity Boards and Electricity Departments,Planning Commission, Government of India, 1997.

Prices for certain oil products, such as kerosene, LPG and fueloil, are subsidised to accommodate the Government’s social policy.A heavy subsidy is set for diesel, because it is mainly used in publictransport, road freight and agricultural irrigation. In 1996/97,diesel subsidies alone amounted to close to 83 billion rupees ($2.4billion).

Not only have subsidies rarely reached their target groups, butpersistent oil pricing distortions have created a “dieselisation of theIndian economy”.

The outcome of deregulation in India and its impact on energypricing present major uncertainties for the projections presentedhere.

One of the notable features of the region’s energy profile is thevery low level of per capita energy consumption. If only commercialenergy is considered, an average of 0.2 tonnes of oil equivalent (toe)was consumed per person in 1995. In Bangladesh, Nepal and SriLanka, per capita consumption was well below the regional average.This is the lowest level of per capita energy consumption among allthe developing regions. Even in Africa, per capita energy consumptionwas 0.3 toe in 1995 and, in China, it was 0.7 toe.

As presented in Table 17.3, the GDP of the region is assumed, inour projection, to almost triple over the period to 2020, an annualgrowth rate of 4.2% per year. The achievement of this growth willdepend on the broadening and deepening of the energy sector reformprogramme, especially in India. The sustainability and success of the

Fiscal Year 90/91 91/92 92/93 93/94 94/95 95/96 96/97

Average Price 81.8 89.1 105.4 119.3 129.3 144.4 149.2(Paise/kWh)Average Cost 108.6 116.8 128.2 144.3 157.7 173.6 186.2(Paise/kWh)Price/Cost 0.75 0.76 0.82 0.83 0.82 0.83 0.8


reform process remains one of the key uncertainties surrounding theprojections presented in this Outlook. It is expected that the slowingof population growth will continue, with an average annual growthrate of 1.5% to 2020. Together, the assumptions for economic andpopulation growth imply an average rise in per capita income of 2.6%per year. This leads to per capita income in 2020 of $2433 (inpurchasing power parity terms), around twice its 1995 level, in realterms. Given the various reforms being undertaken in India, it isassumed that energy prices will, over the course of the Outlook period,begin to reflect more closely their economic costs of supply. Hence, itis assumed that the pre-tax price of oil products and of coal will followinternational spot market prices. An LNG price similar to that forEast Asia has been assumed, even though the proximity to the MiddleEast could lead to a lower value.

Table 17.3: Assumptions for South Asia


OverviewIn the business as usual projection, commercial primary energy

demand in South Asia is expected to grow at an average annual rate of4.3% and to reach 811 Mtoe in 2020. This is somewhat higher thanprojected energy demand in OECD Pacific. Coal and oil continue todominate the primary fuel structure, supplying more than three-quarters of commercial primary energy demand in 2020. Natural gashas the fastest rate of growth of any fuel. At the level of final energy

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal Price ($1990 per metric ton) 44 40 42 46 0.5%Oil Price ($1990 per barrel) 6 15 17 25 2.1%LNG Price ($1990 per toe) n.a. 126 141 210 2.1%GDP ($Billion 1990 and PPP) 528 1548 2928 4346 4.2%Population (millions) 716 1219 1572 1786 1.5%GDP per Capita ($1000 1990 and 0.7 1.3 1.9 2.4 2.6%PPP per person)


demand, the share of coal falls relative to increases in demand for gas,oil and electricity. Commercial energy intensity in the region isexpected to remain broadly unchanged.


Total final commercial energy demand is expected almost to tripleover the Outlook period, with an annual average growth rate of 4.2%.The share of coal falls significantly. Gas is the fastest growingconventional fuel. The transportation sector will be the main driverfor the expected increase in oil demand. Despite projected stronggrowth of electricity, per capita electricity consumption remainsextremely low by international comparisons.


1971 1995 2010 2020 1995-2020Annual

Growth Rate

TPES 72 284 558 811 4.3%Solid Fuels 39 140 256 348 3.7%Oil 27 99 191 277 4.2%Gas 3 34 90 160 6.4%Nuclear 0 2 4 5 3.7%Hydro 3 10 17 20 2.9%Other Renewables 0.0 0.0 0.7 0.8 22.9%

1971 1995 2010 2020 1995-2020Annual

Growth Rate




Stationary SectorsDemand for energy in stationary uses is projected to rise in line

with GDP in a nearly linear manner at an annual growth rate of 3.7%over the Outlook period. As shown in Figure 17.3, an interestingfeature is that coal - which is now the dominant fuel in stationary usesof fossil fuel with a share of about 46% - is expected to be overtakenby oil within a decade, and by gas within about two decades.

In the residential/commercial sector, the consumption of non-commercial biomass energy is by far larger in absolute terms than theconsumption of commercial energy. It is estimated that the share ofnon-commercial biomass use in the final consumption of this sectoraccounts for about 85%. However, the efficiency of use of non-commercial biomass is low so that the useful energy it provides is alsolow. Household income is expected to continue to be the majordeterminant of both the amount of energy consumed and the choiceof fuel used in this sector. Demographic trends, such as urbanisation,will also affect future development of the energy use levels in theresidential/commercial sector.


0

20

40

60

80

100

120

500 1000 1500 2000 2500 3000 3500 4000 4500


mill

ion

tonn

es o

il eq

uiva

lent

Solid Fuels Oil Gas

1971 - 1995

1996 - 2020



Industry is a major consumer of commercial energy in SouthAsia, accounting for just over half of final energy demand in 1995.India again dominates the region with 86% of industrial energyconsumption.

The economic reforms being undertaken in the region are likelyto have important consequences for the pace and structure ofindustrial growth over the Outlook period. The industry sector inIndia is targeted to lead the economic development process, and itsrate of growth will probably be higher than in the recent past. Energydemand growth will be moderated to the extent that structural changefavours less energy-intensive activities. This is likely to occur as theregion’s economies reap the benefits of international tradeliberalisation and pursue their comparative advantage in labour-intensive manufacturing. Industrial energy demand has been analysedin three sub-sectors, iron & steel, chemicals-petrochemicals and otherindustry. Industrial demand is projected to increase by two-and-a-halftimes between 1995 and 2020. A significant change in fuel mix is alsoprojected: the current 52% share of coal in total industrial demand isprojected to decline to 31% and gas is expected to increase its sharefrom 16% now to 31% in 2020. Oil is projected to decrease its marketshare from 18% to 16%.

MobilityFigure 17.4 shows energy demand for mobility in South Asia

continuing to grow in a linear fashion in relation to GDP.Consumption is projected to triple over the Outlook period, at anaverage growth rate of 4.5% a year. The main determinant of thisgrowth is the expected increase in disposable income and growth inthe industrial sector. Growth from the current low level of passenger

1971 1995 2010 2020 1995-2020Annual

Growth Rate



vehicle ownership - 4.5 per 1000 people - is expected to contributesignificantly to this projection. Another contributing factor is a declinein rail traffic in the region. India, like China, has extensive railways,fuelled by diesel oil. This trend is likely to continue in the future. Asthe movement of both people and goods by road is considerably moreenergy-intensive than by rail, this modal shift is expected to be asignificant additional factor in the growth of energy consumption formobility.

Figure 17.4. Energy Use for Mobility


It is expected that more than 60% of the increase in total finalenergy consumption will come from the transport sector. Rapidlyrising oil demand means high import dependence and raises questions

0

20

40

60

80

100

120

140

160

500 1000 1500 2000 2500 3000 3500 4000 4500


mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 17 46 92 141 4.5%


about the long-term security of supply. An important issue concerningoil demand is the product mix. Due to recent pricing policies, theshare of diesel in road fuels is extremely high. The manner andtimetable for phasing out current subsidies and eliminating associatedprice distortions remain key uncertainties for the trends presentedhere.

Box 17.2: “Dieselisation” of the Indian Energy Sector

About 80% of road vehicles in India run on diesel fuel,compared to 15% in China and 31% in Malaysia. Diesel vehiclesare the main source of air pollution in Indian cities. Serious powershortages have forced many institutions to produce their ownpower or install stand-by electricity generation. In most cases,these are powered by diesel oil. Diesel power generators are usedin industrial and commercial establishments (the industrial sectoralone had 15 000 MW of diesel-based captive generation capacityin 1995) and in wealthy urban households. Farmers also prefer touse diesel pumps for irrigation. Even electrified rail-lines also usediesel-fired stand-by generators.

As the diesel price is less than half that of gasoline, car ownershave an incentive to convert gasoline engines to diesel, and manyhave done so. Cheap diesel fuel, combined with high rail freighttariffs (which subsidise passenger tariffs) and the railways’ inabilityto meet demand for some types of freight movement, has given riseto greater use of road freight transport, with trucks fuelled by dieseloil. After comparing the higher electricity tariffs (charged toindustrial consumers to subsidise agricultural and residential uses)with the low diesel price, industrialists find it cheaper to producetheir own electricity using diesel generation than to buy electricityfrom the unreliable grid.

Primarily as a result of this process, the volume of importeddiesel increased by 49% in fiscal year 1995/96 (from 8.64 to 12.85million tonnes). In the same year, diesel accounted for 46% of oilconsumption in India, (up from 40% in fiscal year 1990/91) andthe highest in the world.


Table 17.8: Evolution of India’s Diesel Consumption and Imports(1990-1996)

Source: India’s Energy Sector, Center for Monitoring Indian Economy, September 1996.

ElectricityElectricity demand in South Asia is expected to increase by 5%

per annum over the Outlook period, significantly faster than theregion’s asssumed GDP growth rate. Its current 17% share of totalfinal consumption will increase to 21% in 2020. In 1995, about 44%of this electricity was used in industry, 54% in theresidential/commercial sector and the remaining 2% in other sectors.

Figure 17.5: Total Final Electicity Demand

0

20

40

60

80

100

120

500 1000 1500 2000 2500 3000 3500 4000 4500


mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020

Year (April-March) 1990/91 91/92 92/93 93/94 94/95 95/96

Total Oil Consumption 55.0 57.0 58.9 60.7 65.4 72.5(TOC), in million tonnes

High Consump.Vol. 21.9 22.7 25.5 26.4 28.2 33.5Speed (Mt)Diesel HSD as % of 40 40 43 44 44 46(HSD) TOC

% of HSD 21% 23% 28% 29% 31% 38%Import



In industry, the share of electricity is expected to grow from 14%to 22%. This rapid expansion is mainly due to a shift toward lessenergy-intensive activities in other industry and the increasedpenetration of electric technologies such as arc furnaces in iron andsteel production. Electricity demand in the residential/commercialsector is projected almost to triple over the Outlook period. A rapidincrease in electrical-appliance ownership and the continuingelectrification of rural areas will contribute significantly to the highgrowth of electricity demand. An uncertainty surrounding thisprojection is future Government policy on agricultural electricityprices. Currently, agriculture uses more than a quarter of total finalelectricity in the region and the phasing out of subsidies foragricultural electricity could reduce the trends presented in thisOutlook.

Supply

Power GenerationGrowth in electricity generation in the region has followed trends

in other Asian countries. It averaged 8% growth in the period 1971 to1995. The region is characterised by chronic electricity shortages, asdemand growth has outpaced supply. Shortfalls in building new powerplants, poor-quality transmission lines and theft are the main reasonswhy supply cannot match demand. Plant load factors are often low,due to the age of generating units, lack of the appropriate quality ofcoal, equipment deficiencies and poor maintenance. In India forexample, in 1995, the average generation shortage was around 9% andthat of peak demand, 18%2. In the country’s eighth plan period (1992to 1997), the capacity of new plants was little more than half the

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 5 31 69 107 5.0%

2. Energy Data Directory and Yearbook 1997/98, Tata Energy Research Institute, New Delhi, 1997.


original target. Recent economic sanctions could slow investmentprojects and future electricity growth. Lack of a national gridaccentuates these shortages; at present some of the states have low-cost surplus power during off-peak periods, while other states continueto operate expensive coal-fired units or face power shortages.

India accounts for 85% of the region’s electricity generation. Itspower system is dominated by coal, the most abundant indigenousresource, the fuel with the most developed infrastructure and the mosteconomic option to meet growth in electricity demand. Pakistan,which accounts for 11% of electricity generation in the region, uses amix of hydropower, oil and gas. Bangladesh uses its gas resource base,while Nepal and Sri Lanka rely almost exclusively on hydropower.

Table 17.10: Electricity Generation in South Asia 1995 (TWh)

In the BAU projection, electricity generation grows faster thanGDP, at 5% per annum over the Outlook period, to reach 1657 TWhby 2020. Installed capacity increases at 4.3% per annum, from 106GW in 1995 to 304 GW in 2020. The growth in capacity is lowerthan the growth in electricity generation, because of improvements inthe performance of power plants, the combined effects of higherutilisation of existing capacity and the introduction of new, moreefficient generating plants.

The region is expected to remain dependent on coal-firedgeneration which is projected to increase at 5.2% per annum and toreach 1026 TWh by 2020. The share of coal-based electricityincreases, from 59% in 1995 to 62% by 2020. Coal plant efficiency isvery low, at 27% in 1995, and rises to a potential of 34% in 2020.Coal consumption could therefore grow at 4.2% per annum, from 93Mtoe in 1995 to 262 Mtoe in 2020.

Bangladesh India Nepal Pakistan Sri Lanka South Asia

Solid Fuels 0 288 0 0 0 288Oil 2 12 0 16 0 30Gas 9 25 0 14 0 48Nuclear 0 7 0 1 0 8Hydro 0 83 1 23 4 112Renewables 0 0 0 0 0 0Total 11 415 1 54 5 485


Oil-fired generation is projected to increase from 30 TWh in1995 to 96 TWh in 2020. A number of projects under construction,or at various stages of planning, will use fuel oil, naphtha or diesel oil.Many CCGT projects under development in India will be naphtha-fired at an initial stage; later on, they will switch to gas when LNG orpipeline gas becomes available.

Several gas-fired projects under development in Bangladesh useindigenous natural gas. In India, where domestic gas production issmall, there are some plans to use imported LNG. Pakistan also seeksto reduce its reliance on fuel oil. Electricity generation from gas in theregion as a whole is projected to increase from 48 TWh in 1995 to 277TWh in 2020. Accelerated growth is projected for the second half ofthe Outlook period, when current plans to expand gas fields, gaspipelines and LNG terminals could materialise.

Table 17.11: South Asia Electricity Generation (TWh)

Both Pakistan and India use nuclear power. India’s nuclearprogramme began in 1969, with the commissioning of the Tarapurplant in Maharashtra. The plant has two boiling-water reactors of 150MW each. Four more nuclear plants use twin PWRs with a totalcapacity of 1618 MW. A small fast-breeder at Kalpakkam (13 MW)connected to the grid in July 1997. The performance of these plants ispoor. In OECD countries, nuclear plants operate in baseload modeand their load factors are 75% to 80%; in India, nuclear plants haveload factors of less than 50%. There are four nuclear units underconstruction: Kaiga 1 and 2, and Rajasthan 3 and 4. Each unit has acapacity of 202 MW. Other plants are at various stages of planning.

1995 2010 2020



Table 17.12: Indian Nuclear Plant Performance

Pakistan has had a Canadian-built 128 MW pressurised heavy waterreactor at Kanupp, since 1972. The country is building a second 300-MW nuclear plant, using Chinese technology, at Chasma in the Punjabregion. There are plans to build a second 300-MW unit at Chasnupp.

We assume nuclear capacity in the region to increase from 2 to 4GW by 2020, despite some plant retirements. Nuclear powergeneration is projected to increase from 8 TWh in 1995 to 19 TWh in2020; this projection assumes that the plant load factor will increasefrom 47% to 57%.

Hydropower currently accounts for 23% of electricity generationin the region and 24% of installed capacity. With the exception ofBangladesh, all countries in the region rely on hydropower as anabundant indigenous resource. At a 60% load factor, India’s hydropotential is estimated at 84 GW. Most of it is located in the north andnorth-east of the country. Only 15% of the potential resource hasbeen developed and another 7% is under development.

Nepal has large untapped hydroelectric resources, around 83 GW,of which 35 to 44 GW could be economically exploited. Hydro plantscould be developed for export of electricity to India. Ten projects of atotal capacity of 23 GW have already been identified. Only 12% ofthe country’s 20 million people have access to electricity. Developmentof hydroelectric power poses some environmental problems.

Sri Lanka relies almost exclusively on hydro-power. A number ofsmall hydro projects are under development, but in the longer termthe country will have to increase the use of fossil fuels in the powersector.

Recently, the government of Pakistan announced a three-year banon new thermal projects, in an effort to promote hydropower.

Hydro-electricity in the region is projected to double over the

Year Capacity (MW) Generation (GWh) Plant Load Factor

1990 1425 6141 49%1991 1632 5525 39%1992 1839 6726 42%1993 1839 5398 34%1994 1839 5648 35%1995 2046 7000 39%


period 1995 to 2020. As resources are exploited, growth in hydro isslowing down and its share in total generation decreasing. Hydropower in South Asia is assumed to grow at 2.9% per annum, which issignificantly lower than average annual growth of 5.3% in the period1971 to 1995. The share of hydro in electricity generation decreasesfrom 23% in 1995 to 14% by the end of the Outlook.

New hydro plant development in the region is problematic, forenvironmental, social, and financial reasons. The World Bankwithdrew funding from Nepal’s 402 MW Arun-3 project in 1995 forenvironmental reasons. Construction of the 2400 MW Tehri dam inIndia was suspended following environmental protests. Localpopulations are opposed to the construction of the 400-MWMaheshwar dam in central India. Completion of the 1450 MW GhaziBarotha dam in Pakistan will be delayed for lack of financing.

Non-hydro renewable energy for power generation is receivingincreased attention. Alternative energy supplies are used in the regionto provide electricity in rural areas, particularly where early connectionto the grid is not envisaged. In India alone, total renewable capacity atthe beginning of 1997 was 1400 MW. The target for renewablecapacity in the country’s Ninth Plan (1997-2002) is 3000 MW.

Table 17.13: India’s Estimated Renewable Energy Potential (GW)

Sources: India Power, Vol. V. No. 2, April-June 1997, Council of Power Utilities, New Delhi,1997. Energy Data Directory and Yearbook 1997/98, Tata Energy Research Institute, New Delhi,1997.

Wind power is the most promising of all renewables. Windcapacity in India was 900 MW in March 1997 and is increasing. Solarpower is also becoming popular. Bangladesh recently commercialised a62 kW solar power plant near Dhaka and there are 35 independentsystems with a total capacity of 30 MW. In India, there are more than350000 systems with a total capacity of 25 MW, which could expandto 150 MW by the end of the Ninth Five Year Plan. The country alsohas larger grid-connected plants of 25-100 MW. Two 50 MW units

Source Potential

Biomass 6Wind 20Small Hydro 10Ocean 50


are planned in Rajasthan. In India there are 18 projects using biomass, with a total capacity

of 69 MW. Another 17 projects totalling 97 MW are planned.Bangladesh plans to build a waste-and-gas plant that will use domesticand industrial waste from the city of Dhaka and domestic natural gasor waste gases from a waste dump.

CoalIndia is the only major producer of coal in the region. Output has

increased rapidly since the early 1970s. India is now the world’s fourthlargest coal producer, after China, the United States and the formerSoviet Union. Production increased from about 75 million tonnes in1971 to 333 million tonnes in 1997, of which 310 million tonnes washard coal and 23 million tonnes brown coal. Some coal is exported toBangladesh and Nepal but, overall, India is a net importer of coal. In1997, 15 million tonnes were imported, mostly coking coal.

As shown in Table 17.14, proven reserves in India were estimatedat 68.6 billion tonnes at the end of 1995, of which three quarters arefound in Bihar, Madhya, Pradesh and West Bengal. While reserves aresubstantial, Indian coal is generally of poor quality, high in ash and oflow calorific value. Domestic coal must be washed to make it suitablefor use in coke ovens. Productivity is low by international standards asmechanisation is largely limited to coal cutting. Coal loading ispredominantly by hand.

Table 17.14: Indian Coal Reserves by Type and State, as of January 1995(billion tonnes)

Source: GOI Planning Commision, Draft Mid-Term Appraisal of Eighth Five Year Plan, 1997.

Average coal production costs are low by international standards,and have been kept stable in real terms by lower costs in newdevelopments. The average cost at Coal India’s surface mines was$7.12 per tonne (1993), and $20.60 for underground production(1994). Costs are expected to rise as stripping ratios increase.

Coal Reserves Proved Indicated Inferred Total

Coking Coal 15.1 13.3 1.5 29.9Non-Coking Coal 53.5 76.4 40.2 170.1Total 68.6 89.8 41.7 200.0


An additional problem in the coal sector is that reserves aremainly found far from major consuming centres. About three-quartersof coal production is moved by rail, either by the public sector IndianRailways or by dedicated rail transport, to power plants. This places aconsiderable burden on the Indian rail system. Projections for coalconsumption in India mean that substantial investment will berequired in transport capacity. The remaining coal output is movedeither by truck or by coastal vessels.

In order to meet the projected 250% increase of current coaldemand, it will be necessary to increase imports, most of which will besteam coal.

OilIndia’s oil fields are located in the Bombay High, Upper Assam,

Cambay, Krisha-Godawari and Cauvery basins. In 1997, Indiaproduced 760 000 barrels a day of oil.

Output from the offshore Bombay High field, which accounts forroughly half of Indian oil production, has been declining slowly inrecent years, and this trend is likely to continue. A gas reinjection andreservoir pressure maintenance programme for the field has been understudy for years, but has not progressed beyond that stage. Althoughproduction from private sector and joint venture fields has been growing,this is unlikely to reverse continued gradual declines in Indianproduction. However, improved Bombay High output could potentiallystabilise Indian supply for a few years. India is becoming increasinglydependent on imports. In 1997, net imports of about 1 million barrelsper day met for more than half of India’s oil demand.

Table 17.15: South Asia Oil Balance (Mbd)

Elsewhere in the region, reserves of crude oil are located inPakistan. Production in 1997 was around 60 000 barrels a day and islikely to remain near that level or decline gradually over the next

1996 2010 2020

Total Demand (incl. bunkers) 2.3 4.1 5.9All Supply 0.8 0.8 0.7Imports 1.5 3.3 5.2


several years. Demand far outstrips domestic supply, reaching about350 000 barrels per day. Net imports were about 285 000 barrels perday in 1997.

Imports of both crude and oil products will remain an importantsource of South Asia’s oil supply throughout the Outlook period.

GasIndia’s natural gas production reached 0.7 trillion cubic feet in

1997. Indian gas reserves are located mainly in the Bombay HighFields. Further major discoveries are likely. India has been self-sufficient in gas to date but the projected increases in gas demand overthe Outlook period will necessitate large imports. Several options arebeing explored, including building facilities to handle imports of LNGand constructing pipelines from major gas-producing countries.

Both Pakistan and Bangladesh have some natural gas reserves.Pakistan currently produces 0.6 trillion cubic feet of natural gas a year,all of which is used in the domestic market. Projected increases in gasdemand will not be met from domestic production, and Pakistan ispursuing options for additional supplies from the Middle East andCentral Asia.

Given the projections for gas demand in South Asia over theperiod to 2020, it is clear that the region will need significant gasimports in the medium term. It will be easy to secure gas supplies fromoutside the region but this will require substantial investment ininfrastructure, either pipelines or LNG facilities. If the requiredinfrastructure development does not keep pace with demand growth,then energy consumption, especially of electricity, will be constrained,or there will be increased reliance on alternative-fuel sources, coal inthe case of India and probably oil in the case of Pakistan.

Biomass

Current Patterns of Biomass Energy UseDespite substantial growth in commercial fuel consumption in

the last two decades, South Asia still relies heavily on biomass energy,which accounts for 56% of final energy consumption and 46% ofprimary energy use. These shares are much higher than those ofChina and East Asia, and closer to those found in Africa. Of all thedeveloping regions, South Asia has the largest annual biomass primaryconsumption, estimated at 244 Mtoe. This is about 23% of world


biomass energy consumption.Within the region, India accounts for 80% of biomass energy

consumption, although estimates vary greatly. As in China, biomassconsumption varies widely among localities, and different methodsused for scaling up from local to national biomass consumption canlead to large differences. The figure of 189 Mtoe, used here as a meanestimate for 1995, is an average of the most reliable and completeestimates. The next two largest biomass users in the region arePakistan, at 9%, and Bangladesh at 7%. Nepal and Sri Lanka jointlyaccount for the remaining 5%.

As shown in Table 17.16, the share of biomass energy in finalenergy consumption varies significantly across the countries of theregions, as does per capita biomass use. Nepal has the highest share ofbiomass consumption, at 90%, as well as the highest per capitaconsumption, reflecting a high availability of biomass fuels combinedwith very low per capita use of conventional energy.

Table 17.16: Final Biomass Energy Use in South Asia, 1995

A large part of biomass energy is consumed in rural households.However, in South Asia, biomass consumption in urban householdsand in the industrial sector is quite significant, accounting for 6%-8%and 10%-15% of total biomass consumption. A unique characteristicof South Asia is the large use of animal waste (representing some 20%-30% of the region’s biomass use) and the very limited use of charcoal.This is probably due to the relatively low availability of wood ascompared with China and East Asia. Another 20%-30% is made upby agricultural residues. Most biomass is burned directly intraditional, low-efficiency devices, although production of biogas from

Total Share of Share of Per capita energy usebiomass in country in biomass (kgoe)

TFC (Mtoe) the region in TFC Biomass Conv. fuels

India 189 80% 55% 203 167Pakistan 21 9% 47% 162 183Bangladesh 16 7% 73% 131 49Nepal 6 3% 90% 293 31Sri Lanka 4 2% 63% 201 118South Asia 235 100% 56% 193 154


animal waste is increasing in India. Use of biomass for the productionof electricity is limited at present, but pilot projects for a number ofsmall plants are underway.

Past TrendsThe lack of consistent historical data makes it difficult to assess

past trends in biomass energy use and the pattern and pace of fuelsubstitution by conventional fuels. Data for India show an impressiveincrease in household consumption of LPG and kerosene in the last 20years (13% and 6% per annum respectively), but surveys suggest thatmost of this increase was absorbed by urban households, with little orno effect on rural areas3. According to some estimates, in India, theshare of biomass energy in rural energy consumption has remainedrelatively unchanged in the last 15 years, while the total amount ofbiomass used has increased, due to rural population growth. This ismainly due to the unavailability of alternative fuels. There have beengradual changes in the relative shares of the different biomass fuels,with shifts from dung and agricultural residues to wood, and fromcollected wood (twigs) to marketed wood (logs)4.

ProjectionsIt is expected that per capita biomass use in South Asia will slowly

decline over the Outlook period. The total amount will continue toincrease, from 244 Mtoe now to 308 Mtoe in 2020, due to populationgrowth. This represents an average annual growth rate of less than1%, compared with 4.3% for conventional primary energy fuels. As aresult, the biomass share in total primary demand is projected todecline from 46% in 1995 to 28% in 2020. Figure 17.6 summarisesthe biomass projections for South Asia.

Given the importance of biomass in South Asia, the inclusion ofthis energy source in the analysis can greatly affect the messages andinferences that can be drawn. For example, energy intensity includingbiomass is at a very high level and is declining quite rapidly. Thiscontrasts with the relatively flat path for energy intensity when it iscalculated using only conventional energy. This comparison is shownin Figure 17.7. This inconsistency arises because biomass fuels are

3. Demand for LPG in urban areas, National Council of Applied Economic Research, New Delhi,India, 1985 and 1995 (unpublished).4. Natarajan, Demand forecast for biofuels in rural households in India, in IEA, Biomass Energy:Data, Analysis and Trends, Workshop Proceeding, forthcoming.


generally used in a very inefficient way and their substitution byconventional fuels will result in a gain of overall efficiency.


Figure 17.7: Energy Intensity with and without Biomass,1995-2020

0

200

400

600

800

1000

1200

1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent


100

150

200

250

300

350

1995 2000 2005 2010 2015 2020

toe

/ $1

000

(199

0 pr

ices

and

PPP

)



Chapter 18 - Latin America 347

CHAPTER 18LATIN AMERICA

IntroductionLatin America includes economies with very different

characteristics and dynamics1. The population of the region in 1995was estimated to be close to 480 million people and its GDP was$2634 billion (based on purchasing power parity and 1990 prices),equivalent to GDP per capita close to $5500. The region accountedfor around 9% of world’s GDP.

Latin America is an important exporter of primary commodities,including energy, and its economy is sensitive to changes incommodity prices, although the region is undergoing a structuralchange to a more industrialised economy. There is vast hydro potentialand, despite the dominance of hydropower in the power generationsystem of most countries in the region, only a fraction of this potentialhas been utilised. Venezuela and Mexico have important hydrocarbonresources. The region is relatively energy intensive in terms of finalenergy, but its global environmental impact in terms of energy-relatedCO2 emissions is limited, due to its extensive use of hydro andbiomass. Part of the reason for the high final energy intensity in theregion is its increasing share of the world’s production of some energyintensive goods, like steel and aluminium.

Latin America has experienced rather modest economic growthsince 1971, slightly over 3% per annum. In 1997, GDP growth averaged5%, approaching rates recorded before the first oil crisis. Economicgrowth was especially strong in Argentina, Peru, Chile and Venezuela.Mexico, despite the recent oil price fall, appears to have recovered fromthe recession triggered by its 1994 financial crisis. The Mexican economyregistered growth of 5% in 1996 and 7% in 1997. On the other hand,problems related to fiscal and monetary policies have prevented highergrowth in Brazil, which accounts for one third of the region’s total GDP.

1. This region includes the following countries: Argentina, Bolivia, Brazil, Chile, Colombia, CostaRica, Cuba, Dominican Republic, El Salvador, Ecuador, Guatemala, Haiti, Honduras, Jamaica,Mexico, Netherlands Antilles, Nicaragua, Panama, Paraguay, Peru, Trinidad/Tobago, Uruguay,Venezuela, Antigua and Barbuda, Bahamas, Barbados, Belize, Bermuda, Dominica, FrenchGuiana, Grenada, Guadeloupe, Guyana, Martinique, St. Kitts-Nevis-Anguilla, Saint Lucia, St.Vincent-Grenadines, and Surinam. Please note that following countries have not been consideredin this Outlook due to lack of data: Aruba, British Virgin Islands, Caymen Islands, FalklandIslands, Montserrat, Saint Pierre-Miquelon and Turks and Caicos Islands.


Table 18.1: Economic and Population Data for Selected Latin AmericanCountries

Table 18.2: Energy Consumption in Selected Latin American Countries,1995 (Mtoe)

A key feature of the Latin American economy is the process oftrade liberalisation. This is expected to have increasingly importanteffects on economic and energy developments in the region. Manycountries are striving to stabilise inflation and to modernise theirindustries using imported technology and capital. Liberalisation islikely to have a significant impact on energy use, through theupgrading of the technological infrastructure of the region. Theenergy supply potential is likely to be enhanced and increasing energytrade will lead to greater overall economic efficiency. A major step in

GDP Population GDP per Capita1995 Growth Rates 1995 Growth Rates 1995

($ Billion 1990 (1985-95) (millions) (1985-95) ($ 1000 1990 andand PPP) (annual, %) (annual, %) PPP per person)

Mexico 642 1.6 95 2.0 6.8Brazil 882 2.2 159 1.6 5.5Argentina 235 2.7 35 1.4 6.8Venezuela 162 2.8 22 2.4 7.5Colombia 185 4.5 37 1.8 5.0Chile 154 7.0 14 1.6 10.9Regional Total 2634 2.5 478 1.8 5.5

Primary Energy Supply Final Consumption

Total Coal Oil Gas Total Electricity

Mexico 125 5 85 26 88 10Brazil 123 12 82 4 105 22Argentina 53 1 24 24 38 5Venezuela 47 0 18 25 34 5Colombia 24 4 13 4 19 3Chile 15 2 10 1 12 2Regional Total 452 25 281 93 342 53

this direction is MERCOSUR (Mercado Comun del Sur - theSouthern Cone Common Market agreement). The members areArgentina, Brazil, Paraguay and Uruguay, and associate members areBolivia and Chile. This agreement creates a free trade area of morethan 200 million people. MERCOSUR became fully effective in1995; it provides for common external tariffs in 85% of traded goods.Mexico is also a member of NAFTA (North American Free TradeAgreement), which was implemented in 1994. NAFTA has liberalisedMexico’s trade with the United States and Canada. In 1997, Mexicodisplaced Japan as the second largest importer of US goods. Otherregional trade pacts are actively being discussed.

Restructuring and deregulation of the energy sector may alsoaffect future energy trends in Latin America. The future of tradeliberalisation and energy sector restructuring create key uncertaintiessurrounding the projections presented in this Outlook.

Box 18.1: Restructuring of the Latin American Energy Sector

The energy sector of Latin America is undergoing substantialchange in almost all countries. The main aims of the reforms are toderegulate parts of the energy supply industry and to reducemonopolies.

Private capital is increasingly allowed to play an important rolein energy sector development, either through the privatisation ofstate-owned companies, such as YPF, the former state-owned oilcompany, in Argentina, or in competition with state utilities. Thistrend can have a significant impact on the energy sector.

In the hydrocarbon sector, both oil and gas supplies are likelyto increase as a result of the introduction of private capital, themore competitive environment and the increasing participation offoreign companies. The region is well endowed with oil and gasresources. A key constraint on capacity expansion in the past hasbeen limited investment.

Almost every country in the region is in the process ofreforming the regulatory framework for the power distributionsector, aiming at creating a level playing field which, in turn, willpromote competition and attract private investment in the wholeelectricity system. Competition in generation is expected to lowercosts through increased operating efficiency and investment in gas-fired plants with high thermal efficiency.



Total primary commercial energy demand in Latin Americaincreased at an average annual rate of about 4% between 1971 and1995, to reach over 450 Mtoe. The predominance of oil in overallprimary and final energy demand, and the importance of hydro in thegeneration of electricity, are two striking features of the region as awhole. Energy systems of individual countries, however, are quitedistinct, with Argentina being one of the most gas-intensive countriesin the world, while the energy systems of the poorest countries are stilldominated by biomass.


The fuel structure of primary energy demand changedsignificantly since 1971. As shown in Figure 18.1, oil and gas stillaccount for more than 80% of the region’s primary commercial energydemand. While oil has continued to be the dominant fuel, its sharefell from 76% in 1971 to just above 62% in 1995. Over the sameperiod, the share of gas increased from 15% to 20%. This shift hasbeen the outcome of changes in relatively few countries. The majorimpetus has been to conserve oil supplies for export or to reducedependence on imported oil. As large-scale hydro schemes have beenconstructed in several countries, hydro’s share in electricity generationhas increased to about 64%, from 53% in 1971. Over the Outlookperiod, the share of hydro is projected to decline, partly due to therestructuring of the sector that will favour smaller, less costly schemesbased on gas. Coal has always played a small role in the region’s energy

Solid Fuels 6%

Other Renewables 1%

Hydro 9%

Nuclear 1%

Gas20%

Oil62%

Solid Fuels 6%

Other Renewables 1%

Hydro 9%

Nuclear 1%

Gas31%

Oil53%

1995 2020

452 Mtoe 986 Mtoe


balance, except in those countries where indigenous resources areavailable, such as Colombia, or where alternatives such as gas areunavailable. As in other developing regions, non-commercial biomassfuels, mostly wood and sugar cane products, are also used to meetenergy demand.

Table 18.3 shows that economic activity in Latin America isassumed to grow at 3.3% over the Outlook period. This is almost thesame rate as in the last two decades. The longer-term economicOutlook is expected to be strengthened by the effects of tradeliberalisation and consequent productivity improvements. Populationgrowth is assumed to slow down to 1.3% on average over the Outlookperiod, down from around 1.8% in the last decade. Thus, per capitaincomes are likely to increase at about 2% per annum and reach a levelof $9000 (in purchasing power parities and 1990 prices) in 2020. Itis assumed that domestic energy prices will follow international pricetrends.

Table 18.3: Energy Price Assumptions for Latin America


OverviewIn the business as usual case, commercial energy demand in Latin

America is projected to grow at an average annual rate of 3.2% and toreach almost 1000 Mtoe by 2020. This is almost identical to theassumed GDP growth rate over the Outlook period. Oil is expectedto remain the dominant fuel, but its share drops to 53% from 62%.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal Price ($1990 per metric ton) 44 40 42 46 0.5%Oil Price ($1990 per barrel) 6 15 17 25 2.1%Natural Gas Price ($1990 per 0.6 1.3 1.7 2.5 2.5%1000 cubic feet)GDP ($Billion 1990 and PPP) 1186 2634 4410 5944 3.3%Population (millions) 289 478 589 659 1.3%GDP per Capita ($1000 1990 and 4.1 5.5 7.5 9.0 2.0%PPP per person)


This will be made up mainly by gas, growing at an annual average rateof almost 5%. Hydro will retain its 9% share. No substantial changesin the shares of other fuels are expected.


Total final commercial energy demand is expected to more thandouble, at an annual average growth rate of 2.9%. The shares of oiland coal are expected to decline and those of gas and electricity toincrease. In 2020, oil is expected to hold a share of close to 60% intotal final commercial energy consumption, the second highest shareafter East Asia, amongst regions analysed in this Outlook. More than70% of incremental final oil demand is projected to come from thetransportation sector.


1971 1995 2010 2020 1995-2020Annual

Growth Rate


1971 1995 2010 2020 1995-2020Annual

Growth Rate




Stationary SectorsEnergy demand for stationary services is expected to rise broadly

in line with GDP, at an annual rate of 2.6%. While oil and coaldemand are expected to increase moderately, gas use is projected to riserapidly, at 4% over the Outlook period.

Future trends in residential/commercial energy demand willdepend on per capita income levels, the urbanisation rate and thespeed of substitution of non-commercial fuels by commercial energy.Trends in end-use prices will also affect the demand Outlook for thesector. In some Latin American countries, there has already been arestructuring of energy prices in recent years to bring them closer tointernational levels. In other countries, however, end-use prices (forthe household/commercial sector) remain below international levels.In the projections presented here, it has been assumed that allcountries in the region gradually adopt a more market-orientedapproach to the pricing of energy products.

The industry sector accounts for over a third of final commercialenergy consumption and has grown rapidly since 1971, as the regionembarked on a programme of industrialisation, often led by the mostenergy intensive sectors. Given the region’s potential for using itsresource industries as a base for moving into higher value-addedproducts, it is assumed in this Outlook that industrial production willgrow faster than GDP. Energy demand growth in industry, however, islikely to lag behind industrial production, as energy prices continue toapproach international levels.


1971 1995 2010 2020 1995-2020Annual

Growth Rate




MobilityDemand for mobility in Latin America is projected to increase in

a linear fashion along with GDP. At an average annual growth rate of2.8%, the current level of consumption is expected to double over theprojection period. Compared to other developing regions, LatinAmerica has a relatively high degree of vehicle ownership, reflectinghigher per capita incomes, high levels of urbanisation, a history of low,subsidised prices for transport fuels across the region and the largedistances between cities. But there are large differences within theregion, with the number of passenger vehicles per 1000 people in1996 about 9 in Guatemala, 130 in Argentina, 84 in Brazil (in 1993)and 95 in Mexico2. There is still a substantial potential for increase invehicle ownership as incomes rise.

There have been many initiatives to encourage the use ofalternative fuels in the region. These include an alcohol fuelsprogramme in Brazil and the promotion of compressed natural gas inArgentina, Colombia and Chile. These programmes have affected thefuel mix in these countries in varying degrees, mainly through

0

20

40

60

80

100

120

140

160

1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000


mill

ion

tonn

es o

il eq

uiva

lent

Solid Fuels Oil Gas

1971 - 1995

1996 - 2020

2. World Road Statistics 98, International Road Federation, 1998.


incentives provided by governments. The deregulation process in theregion’s energy markets is expected to affect such programmesadversely. We do not foresee a substantial penetration of alternativefuels in the mobility fuel mix over the projection period.



ElectricityElectricity demand in Latin America is projected to grow by 4.1%

a year over the Outlook period, significantly faster than the assumedGDP growth rate. This implies almost a tripling of electricitydemand. Electricity’s current 16% share of total final commercialconsumption increases to 20% in 2020, when electricity will be thesecond most important energy type after oil.

0

50

100

150

200

250

300

1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000


mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 51 131 204 263 2.8%


In 1995, about 48% of this electricity was consumed in industryand 52% in the residential/commercial sector. In both sectors, theshare of electricity in total final consumption is expected to expand,reflecting rising income levels, urbanisation, structural andtechnological shifts in the industry sector and the increasing use ofelectrical appliances in the residential/commercial sectors.



Supply

Power GenerationLatin America’s electricity generation is unique among the regions

analysed in this Outlook, in that it is highly dependent on the region’s

0

20

40

60

80

100

120

140

160

1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000


mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 12 53 98 144 4.1%


abundant hydro resources. In 1995, hydro electricity accounted for 64%of total electricity output in the region.

Oil has been a significant fuel in electricity generation in the past,but its importance has been declining. Its share fell to 17% in 1995,down from one third of total output in 1971. In place of oil, gas-firedgeneration is becoming increasingly popular, based on increasedproduction of the region’s gas reserves, development of infrastructure todeliver the gas across Latin America as well as growing environmentalconcerns. The most important of these projects is the pipeline that willbring gas from Bolivia to Brazil. Other pipelines are scheduled to deliverArgentinean gas to Chile.

Electricity generation and capacity in Latin America are projectedto grow at around 4% a year. Over the Outlook period, the region’selectricity generation mix could change significantly and become moredependent on fossil fuels, notably on gas.

Table 18.9: Electricity Generation Mix (TWh)

About one third of new capacity in Latin America could come fromhydroelectric plants. Hydro electricity generation is assumed to increaseat 2.8% a year. The rate of growth will slow as the best sites aredeveloped. Consequently, the share of hydro in the electricity generationmix is expected to decline, from 64% in 1995, to 47% by 2020.

Nearly half of Latin American installed hydro capacity, some 51GW, is in Brazil, which has a vast hydro potential estimated at 143GW of firm power per annum3, equivalent to around 289 GW ofinstalled capacity at a 50% load factor. Existing plants, plants underconstruction and plants at the feasibility stage account for nearly two

1995 2010 2020


3. Brazilian Energy Balance 1997, Federative Republic of Brazil, Ministry of Mines and Energy.


thirds of the total potential. Estimates of hydro potential have beenincreasing, even in recent years. In 1990, estimated hydro potentialwas 12% less than the most recent estimate of 143 GW. The Amazonbasin accounts for about 40% of the potential and there are plans toexplore it further in the longer term. Some of the projects in theAmazon area are the 11 GW Monte Belo plant, the 5.7 GW Altamiraplant, the 9.5 GW TA-1 plant on the Tapajes river and the 6.9 GWMR-1 plant on the Madeira river4 .

The ELETROBRAS 10-year expansion plan (1996-2006) callsfor 22 GW of additional hydro capacity. Under longer term plans, theshare of hydro in installed capacity could fall by 2015, but could stillaccount for 80% to 85% of total capacity5.

There are plans to develop several bi-national projects in LatinAmerica that would lead to an integration of energy supplies in theregion. Such plans include: Roncador (2.8 GW), San Pedro (0.8GW) and Garabi (originally 1.8 GW, but development of 1.5 GW ismore likely) on the Uruguay River; Talavera (6 MW) and PasoCenturion (32 MW) on the Jaguarao River and Itati-Itacora (1.7 GW)on the Limay River.

Private participation in hydro schemes is encouraged. Anexample is the Garabi plant, which could be built on the Argentinian-Brazilian border. ELETROBRAS, which is supervising the project onbehalf of the Brazilian and Argentinean governments, is hoping tooffer the project to private investors as a “Build, Operate, Transfer”scheme. Other, unfinished hydro projects in the region are also beingoffered for privatisation.

Gas-fired generation is projected to make spectacular gains, as gassupplies become increasingly available. A large number of CCGTprojects are at various stages of development, as are schemes to convertexisting oil-fired facilities to burn gas. Gas-based electricity generationis set to increase at 8.7% per annum and to account for nearly a thirdof electricity output by the end of the Outlook period.

At the same time, oil-fired generation increases in absolute terms,but its share is projected to decline further. Nearly half of LatinAmerica’s oil-based electricity output comes from Mexico, where oil-fired capacity accounts for half of the country’s total. The liberalisationof Mexico’s gas sector is likely to spur gas use in power generation. Thedeterioration of air quality in urban areas like Mexico City, Monterrey

4. International Private Power Quarterly, 1st quarter 1998.5. Plan 2015, National Electric Energy Plan, 1994, Eletrobras, Rio de Janeiro, 1994.


and Guadalajara has sparked increased environmental concerns. Inthese areas, as well as in Yucatan, existing power stations that currentlyuse fuel oil are planned to change to natural gas. A total of 4.5 GW isscheduled for conversion6.

Solid fuels accounted for only 5% of the Latin Americanelectricity generation mix in 1995, but its share could increase by 3percentage points over the Outlook period and coal-fired capacity islikely to expand from 13 to 31 GW.

Nuclear power plants are in operation in Argentina, Brazil andMexico, with a total capacity of around 2.9 GW, about 2% of theregion’s installed capacity.

Table 18.10: Operating Nuclear Power Plants in Latin America

Argentina’s Atucha-1 was the region’s first nuclear plant. It is aGerman-built reactor of unique design that uses natural uranium andheavy water in a pressure reactor. The plant started commercialoperation in 1974. The second Argentinean plant, Embalse, was builtin the mid-1980s by Canada’s AECL. The country has a third,unfinished plant, Atucha 2, with a capacity of 692 MW. Constructionstarted in 1980, but the plant was never completed. The Argentinegovernment plans to privatise the country’s nuclear sector and to sellthe installations as a package, including the completed Atucha 2. Thisplan is viewed as problematic because the two existing plants are basedon different technologies and construction of Atucha 2 has beenstalled for several years. It is assumed in this Outlook that Atucha 1reaches the end of its operational life by 2004 and that Atucha 2 is notcompleted.

Brazil’s only existing nuclear facility began operation in 1982. Aspart of the Brazil-Germany Nuclear Agreement, the 1975 Brazilianprogramme called for 8 plants of 1245 MW capacity. Of these, only

6. Prospectiva del Sector Electrico 1997-2006, Secretaria de Energia, Mexico, 1997.

Plant Name Size (MW) Country

Atucha 1 335 ArgentinaEmbalse 600 ArgentinaAngra-1 626 BrazilLaguna Verde 2 x 654 Mexico


Angra 2 is under construction and equipment has been ordered forAngra 3. We assume that Angra 2 is completed as scheduled, i.e.,around 2000, and that Angra 3 remains unfinished during theOutlook period.

Mexico’s first nuclear reactor was commissioned in September1990. The second unit was commissioned five years later. Thecountry has no plans to expand its nuclear capacity in the foreseeablefuture.

Under these assumptions, installed nuclear capacity in LatinAmerica could be around 4.5 GW in 2020. The share of nuclearelectricity generation is expected to fall to 1% of total.

In 1995, electricity generation from geothermal energy was 6.7TWh. Most of it, some 5.7 TWh, was generated in Mexico, whichwas, in that year, the third largest producer of geothermal energy inthe world. The most important geothermal plant is Cerro Prieto, withan installed capacity of 620 MW. Other Latin American countriesthat use geothermal include Nicaragua and El Salvador. It is assumedthat electricity generation from geothermal sources nearly doubles bythe end of the outlook.

Wind power is currently in use in some countries, but at a verysmall scale. Mexico has included a 54 MW project in its 1997-2006electricity plan7.

Biomass, particularly bagasse (sugarcane refuse), has found someapplications in electricity generation in several Latin Americancountries. Over the outlook period, this could increase from 9.6 TWhin 1995 to 17 TWh by 2020.

Co-generation is used in several countries but lack of sufficientdata makes it difficult to project future levels.

OilMajor oil producing countries in the region are Mexico,

Venezuela, Brazil, Argentina and Colombia. Mexico and Venezuelaare large oil-exporting countries. In Mexico, the oil industry providesabout 40% of government revenues. Mexico’s official reserves wereestimated at 40 billion barrels as of end 19978 and it produced about3.4 million barrels of oil per day in 1997, of which half was exported.

7. Prospectiva del Sector Electrico 1997-2006, Secretaria de Energia, Mexico, 1997.8. This and the following oil reserve figures are taken from BP Statistical Review of World Energy1998, on-line data; data on production are taken from the IEA’s Oil Market Report.


More than half of Mexican production is heavy Mayan supply fromthe offshore Bay of Campeche area. This output is likely to continueto grow in coming years. The key variable in the Mexican outlook isthe upstream budget of PEMEX, the state owned oil company, sincethe country has an ample resource base. PEMEX has responsibility forthe entire upstream sector and most of the downstream sector inMexico. The prospects for PEMEX to continue to have substantialexploration and production budgets are good. In an environment ofgrowing domestic demand, the government is expected to support oilproduction in order to maintain strong oil export revenues.

Venezuela, a member of OPEC, is one of the most energy-endowed countries in the world. If its extra-heavy oil deposits in theOrinoco belt are included in reserves, then its oil resources arecomparable to those of Saudi Arabia. Official oil reserves amounted to72 billion barrels at the end of 1997, with the bulk of this consistingof heavy or extra-heavy oil. The state-owned oil company PDVSAexpects to maintain its official reserves at current levels for theforeseeable future. Venezuela produced about 3.5 million barrels ofconventional and unconventional oil per day in 1997. Over the pastthree years, Venezuela has raised both its oil production capacity andoutput by more than 200000 barrels a day each year. Futureproduction increases are likely to come from El Furrial Trend and theOrinoco Belt, both located in the eastern part of the country. Theparticipation of foreign joint venture partners is a key element toVenezuela’s plan to increase production. The partners will provideboth investment capital and technical expertise.

Brazil also has significant oil reserves. Its current official reserveswere estimated at about 4.8 billion barrels as of end 1997. The bulkof the current reserves is located in the offshore Campos basin. In1997, Brazil produced 1.1 million barrels of oil per day, including 260thousand barrels per day of alcohol fuels. Despite this productionlevel, Brazil needs to meet about 40% of its consumption throughimports, mainly from Argentina, Saudi Arabia and Venezuela.Increases in oil production are likely to be driven by deep-water fieldsin the Campos Basin, such as Marlim, Barracuda, Albacora, andRoncador; however, self-sufficiency appears to be unlikely in the nexttwo decades.

Argentina, with oil production of about 900 thousand barrels aday in 1997, does not appear to have the geological potential forincreasing production substantially. Significant volumes of reserves


need to be discovered soon if the current level of production is to bemaintained in the long term. The drastic restructuring of YPF, theformer state-owned oil company, as well as increased privateinvestment, are seen by many as a model for solving problems in theupstream oil sector in the other countries of the region.

Colombia’s oil industry got an important boost after the discoveryof the giant Cusiana field in 1991. In 1997, Colombia producedabout 660 000 barrels of oil per day, of which more than 300 000 wereexported. By 1999, full production from Cusiana and the nearbyCupiagua field is likely to be reached. Production from otherdiscovered, but so far undeveloped, fields is likely to augmentColombian production.

Ecuador’s potential is limited by export pipeline constraints, thematurity of many existing fields and the need to replace reserves; it isunlikely to be in a position to increase its production capacitysignificantly. The positions of Peru, Trinidad and Tobago are similarto that of Ecuador. Details of the Outlook’s oil supply projections forLatin America can be found in Chapter 7.

GasLatin America’s gas reserves were estimated to be around 286

trillion cubic feet at the end of 1997 and are located mainly inVenezuela (50%), Mexico (22%) and Argentina (9%). These threecountries also account for 80% of the region’s gas production, withroughly equal shares in 1996.

Natural gas production in Latin America reached 111 Mtoe in1996, 9% above 1995 production. Gas production has increasedrapidly during the last three years: annual growth averaged 6.6% in1993-1996, compared to 2.5% in the previous decade. Gas tradeamong the countries of the region is increasing as infrastructure isdeveloped. The largest exchanges are currently between Bolivia andArgentina. In 1995, Bolivia exported 1.7 Mtoe, or 68% of itsproduction to Argentina.

Mexico produced 30 Mtoe of natural gas in 1996 from reserves of64 trillion cubic feet. Given rapidly increasing domestic demand,imports from the US have been used as swing supplies. The majorproblem for Mexico is that most of the gas is produced in the south-eastern part of the country (most gas produced is associated with oilproduction in the Bay of Campeche), far from main consuming areasin the north. In 1995, Mexico initiated reforms in its natural gas


sector aimed at encouraging greater use of gas throughout the countryand, more specifically, private sector investments in natural gasstorage, transportation and distribution. The private sector responsehas been favourable.

Venezuela’s gas reserves are estimated to be around 143 trillioncubic feet. In 1996, Venezuela produced 29 Mtoe of natural gas. Asin Mexico, all of the gas produced in the country is consumed in thedomestic markets; about 60% is used in the oil industry for heavy oilrecovery with steam injection, 11% in power generation and the restin petrochemical production and by other industrial/commercialconsumers.

Argentina has the third largest proven reserves of natural gas inLatin America after Venezuela and Mexico. Because most of thesereserves were discovered in connection with oil exploration, currentproduction is concentrated in the same five basins as oil production(Noroeste in northern Argentina, Cuyana and Neuquen in the centerof the country, and Golfo San Jorge and Austral in the south).Argentina’s production reached 28.5 Mtoe in 1996. It also importedsome 2 Mtoe from neighbouring countries. Supply is roughly equallydivided among power generation, industry and residential/commercialusers.

Argentina is the most advanced Latin American country in theprivatisation of its gas industry. Following the 1992 Gas Law, theformer state monopoly Gas del Estado was split into two pipelinecompanies, Transportadora de Gas del Sur SA (TGS) andTransportadora de Gas del Norte SA (TGN), and eight distributors. Amajority of the shares in TGN and most of the distribution operationswere sold to private investors in December 1992. TGS, which suppliesgas mainly to southern Argentina and greater Buenos Aires, wasprivatised in early 1994. The state regulatory agency, ENARGAS, is incharge of regulating the industry and setting rates for natural gascarriers operating under a non-discriminatory “open access” system.

Additional pipeline capacity is needed to serve growing domesticand export markets. TGS and TGN are expanding the capacity ofexisting domestic lines, which are currently almost fully utilised.Export lines are also being developed to serve new markets inneighbouring Chile, Brazil and Uruguay:

• Chile. Two lines to Chile were commissioned in 1997: the 700million cubic feet per day (Mcfd) 290-mile GasAndes line fromthe Neuquen Basin to Santiago, and the 100 Mcfd 30-mile


Methanex line from Tierra Del Fuego to Cabo, which supplies amethanol plant. A 300 Mcfd 590-mile line in NorthenArgentina, Gasoducto Atacama, is under construction and isdue to enter service in 1999. Two other lines are planned: NorAndino, a 280 Mcfd 500-mile line which would run fromNorthern Argentina to Atacama; and Pacifico, a 140 Mcfd 280mile link from Neuquen to Concepcion.

• Brazil. A 900 Mcfd 2000-mile pipeline project, Mercosur,linking the Noreste with southern Brazil, has been proposed,though there are doubts about the adequacy of reserves tosupport the $1.5 billion investment.

• Uruguay. A 450 Mcfd link from Buenos Aires to Montevideo isunder construction. There are plans to extend the line to PortoAlegre in Brazil to link up with the Bolivia-Brazil line currentlybeing built. The fourth largest gas producer in Latin America isTrinidad and Tobago, where recent gas discoveries have morethan doubled reserves in the last five years. The country isexperiencing a burst of investment and growth in the gas sectorand its initial LNG exports are expected to begin in 1999.Current production of 6.4 Mtoe is consumed domestically,primarily in the petrochemical industry.

Bolivia, although not a large producer, is set to become thenatural gas hub of the Southern Cone market. Bolivia currently hasone existing gas export pipeline to Argentina (through which itexported 83% of its production in 1996) with a capacity of 212million cubic feet per day. Bolivia’s future pipeline plans include a linkto northern Chile, a pipeline to Brazil, and one to Paraguay. TheBolivia-Brazil gas pipeline is by far the most important of the projects.The final deal was signed in September 1996 and the pipeline istentatively scheduled to begin gas deliveries to the Brazilian cities ofSao Paulo and Porto Alegre in 1998-99. The contract calls fordeliveries of up to 7 trillion cubic feet over the next 20 years, whilecurrent Bolivian gas reserves are only 4.5 trillion cubic feet.

With the giant Camisea natural gas field (11 trillion cubic feet),Peru could develop into a significant regional producer and exporter ofgas. This is the largest gas field in South America, but it is located inremote jungle more than 1200 km south-east of Lima and it remainsto be seen whether full-scale project development will occur. Wouldthe project come to fruition, Brazil is expected to be a large potentialcustomer for Peruvian gas. There are talks on building a pipeline to


connect the Camisea field to the main Bolivia-Brazil line. TheBolivia/Brazil/Peru pipelines could represent an important link in afuture regionally-integrated gas network for the entire southern cone.

CoalColombia and Venezuela contain the principal coal deposits in

Latin America. The El Cerrejón coalfield of the Eastern Cordillera ofColombia and the coalfields of the neighbouring Zulia region ofVenezuela are the largest of these deposits. In Colombia, substantialresources are found close to the surface. In Venezuela, substantialresources are potentially extractable by underground mining, butpriority is being given to surface mining. Colombia accounts forabout three-quarters of Latin American coal reserves. The El Cerrejóncoalfield contains almost two-thirds of Colombia’s coal and is thesource of nearly all its coal exports.

In 1997, Colombia and Venezuela produced 33 Mt and 6 Mt ofcoal respectively. As shown in Table 18.11, production grew steadilyover the last two decades. Europe is the main export market for LatinAmerican coal, but the southern US is developing as a market andsmall quantities go to Asia. The expansion potential for exports inboth countries depends mainly on improvements in the infrastructurewhich require considerable amounts of investment.

Table 18.11: Hard Coal production - Colombia and Venezuela (Mt)

Biomass

Current Patterns of Biomass Energy UseLatin America is the most economically advanced and urbanised

of the five developing regions9. It has the highest average per capitaincome and the lowest share of agriculture in output (11%). It alsohas the highest level of per capita consumption of conventional fuelsand electricity. The share of urban population is by far the highest ofall non-OECD regions (74%), very close to the OECD average(76%).

1971 1980 1985 1990 1995 1996 1997

Production 2.7 4.1 9.0 22.7 30. 3 33.6 38.4Percentage of World 0.1 0.2 0.3 0.6 0.8 0.9 1.0

9. Africa, Latin America, China, East Asia and South Asia.


In these circumstances, it is not surprising that Latin America alsohas the lowest share of biomass of all developing regions: in 1995,primary biomass consumption was 83 Mtoe, or 16% of total primaryenergy, 18% of total final energy and 32% of stationary energy uses.These numbers are slightly underestimated since, for projectionreasons, the sugarcane-derived alcohol used in the transport sector,mainly in Brazil, has been included with gasoline rather than withbiomass10.

Another distinctive aspect of biomass energy use in Latin Americais the large proportion used in the industrial sector: 46% of finalconsumption in 1995.

The largest biomass user in the region is Brazil, with 37% of theregion’s final biomass consumption11. Mexico, Colombia, Cuba, Peruand Chile together account for another 38%.

Firewood accounts for 60% of all biomass use, and for 93% ofuse in the residential/commercial sector. Bagasse is the next mostimportant biomass fuel, with 25% of total use and 52% of biomassuse in industry. There is comparatively large use of charcoal (8% oftotal biomass), most of it concentrated in Brazil, where charcoal isproduced in large, efficient modern kilns and is used mainly in theproduction of steel.

Past TrendsUnlike the other developing regions, there exist for Latin America

relatively consistent and complete time-series for biomass energy use.According to these data, biomass energy use in Latin Americaincreased at an average annual rate of 0.5% between 1971 and 1995,while its share in the region’s energy mix has declined steadily from34% in 1971 to 18% in 1995. This is, however, the result of verydifferent sectoral trends. While biomass energy use has declined in theresidential/commercial sector both in absolute and relative terms,dropping from 64% in 1971 to 34% in 1995, the use of biomass inthe industrial sector has increased at a sustained rate (2.8% perannum), and its share of total industrial energy use has only slightlydeclined from 28% to 22%.

10. This amounted in 1995 to 6.8 Mtoe, of which 6.7 Mtoe in Brazil and 0.1 Mtoe in Argentina.If it had been included in biomass, the above shares would be slightly higher, i.e. 17%, 19% and35% respectively.11. If alcohol were included, this share would be 43%.


Although these figures are given for the entire region, they are notrepresentative of biomass trends in all countries and sub-regions andare highly influenced by trends in Brazil. As can be observed in Table18.12, biomass use in Brazil decreased significantly over the period1971-199512, but increased in all other countries.

Table 18.12: Final Biomass Energy Use in Latin America, 1995

* Excludes alcohol use in transport sector.

Trends in the different biomass fuels have also been very different:during the period 1971-1995, firewood use declined (at 0.7% perannum), and the use of bagasse, charcoal and black liquor grewsignificantly (2.8% per annum, 3.6% per annum and 11.4% perannum respectively).

ProjectionsIt is expected that current trends will continue during the

Outlook period, with decreasing biomass use in theresidential/commercial sector (-0.6% per annum) and increasingbiomass use in the industrial sector (1.4% per annum), with an overallincreasing trend (0.4% per annum) as shown in Figure 18.5. During

12. If alcohol use is included, however, Brazil’s biomass consumption remains flat rather than decreases.

Final of Share of Share of Biomass energy usebiomass which: country biomass (1971-1995)

energy use* in in the in TFC Resid./(Mtoe) industry region Total Industrial Comm.

Brazil 27.3 69% 37% 21% -0.8% 3.2% -4.3%Mexico 9.4 21% 13% 10% 0.8% 2.2% 0.5%Colombia 6.8 25% 9% 26% 1.9% 4.2% 1.3%Cuba 4.6 98% 6% 38% 2.6% 2.6% 1.3%Peru 3.9 12% 5% 34% 0.7% 1.3% 0.6%Chile 3.2 24% 4% 21% 3.6% 5.2% 3.2%Guatemala 2.8 6% 4% 62% 1.9% -2.8% 2.6%Paraguay 2.3 53% 3% 62% 3.1% 5.9% 1.4%Argentina 2.2 82% 3% 6% 1.1% 1.6% -0.2%Others 10.5 - 14% - - - -Latin America 73.0 46% 100% 18% 0.5% 2.8% -0.8%


the same period, the use of conventional energy increases at muchhigher rates (3.1% in the industrial sector and 3.0% in theresidential/commercial sector13). Thus, the share of biomass isprojected to further decrease from 22% to 15% in the industrial sectorand from 34% to 17% in the residential/commercial sector. Overall,the share of biomass in total final consumption falls from 20% in1995 to 10% in 2020 (and from 16% to 9% in total primary energy).


As can be observed in Figure 18.6, including biomass in theenergy mix alters significantly the level and inclination of the energyintensity curve, which decreases more rapidly, reflecting the decreasingshare of biomass in the energy mix.

0

10

20

30

40

50

60

70

80

90

1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent

Industrial Residential/Commercial

13. Including agriculture.

Figure 18.6: Energy Intensity with and without Biomass,1995-2020

140

150

160

170

180

190

200

210

220

230

240

1995 2000 2005 2010 2015 2020

toe

/ $

100

0 (1

990

pric

es a

nd P

PP)




Chapter 19 - Africa 371

CHAPTER 19AFRICA

IntroductionAfrica is a diverse continent from both economic and energy

perspectives. Figure 19.1 shows some differences between the threesub-regions: South Africa, North Africa and Sub-Saharan Africa1.There are a number of countries with vast resources of oil, gas andcoal. However, the energy sector in the region is largelyunderdeveloped. Africa includes some of the least developed countriesin the world and has the second lowest average income per capita($1530 per head at 1990 prices and purchasing power paritycompared with $1270 for South Asia) among the world regionsconsidered in this Outlook. Population growth is expected to continueto be rapid. In real terms, very limited improvements in the standardof living are expected over the Outlook period. GDP per capita willbe one of the major determinants of energy demand in the region and,at the same time, one of the major uncertainties.

Africa’s share of total world population exceeds 12% and itconsumes less than 3% of the total world commercial energy. Bycomparison, the United States accounts for less than 5% of populationand uses 25% of world energy. As shown in Table 19.1, the currentlevel of commercial primary energy use in the African continent is 226Mtoe, less than that of France. The per capita energy consumptionfigure also underlines the extremely low level of energy use: in 1995, itwas 0.33 toe per capita in Africa, compared to 4.45 toe per capita forthe OECD as a whole.

In 1995, South Africa and North Africa each consumed almost40% of the region’s primary commercial energy. All other countries,which consumed the remaining 20%, account for some 75% of the

1. South Africa is defined here as the Republic of South Africa. North Africa is defined asMorocco, Algeria, Libya, Tunisia and Egypt. Sub-Saharan Africa is defined as the remainingAfrican countries. Please note that the following African countries have not been considered inthis Outlook due to lack of data: Comoros, Namibia, Saint Helena, and Western Sahara.


population. More than half a billion people in Sub-Saharan Africaconsumed 48 Mtoe of commercial energy, less than that consumed inBelgium.

Figure 19.1: GDP and Energy Consumption per Capita by Region

On the supply side, North Africa is an important producer of oiland gas, whereas South Africa is a major supplier of coal. As shown inFigure 19.2, solid fuels accounted for slightly more than one third ofAfrica’s total commercial primary energy demand in 1995. Of thisamount, about 90% was used in South Africa, where the energymarket relies heavily on indigenous resources. Coal accounts for 83%of South Africa’s primary energy demand. Oil is the dominant fuel inthe region’s fuel mix with a share of 43%. North African countries relymainly on oil and gas, consuming 53% and 83% of the continent’s

0

2

468

10

12

141618

20

SouthAfrica

NorthAfrica

Sub-SaharanAfrica

OECD China OtherRegions

1990 US$ (PPP) per capita

toe per capita

0.00.51.01.52.02.53.03.54.04.55.0

SouthAfrica

NorthAfrica

Sub-SaharanAfrica

OECD China OtherRegions

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Total Primary Energy Supply per Capita (left side scale) Electricity Consumption per Capita (right side scale)


total. The relative economic growth rates of these countries have, to alarge extent, determined the regional energy mix. Observedsubstitution across the continent between coal/oil and coal/gas is moreapparent than real, resulting more from the relative economic growthrates of different countries than from any actual substitution. On theother hand, the substitution between oil and gas in North Africa, and,at the level of final consumption, the substitution between electricityand other fuels, are of a more substantive nature. Non-commercialbiomass meets a large proportion of energy demand in many countriesin Sub-Saharan Africa.

Table 19.1: Economic Performance and Population of Selected AfricanCountries

Table 19.2: Energy Demand in Selected Africa Countries (Mtoe)

GDP Population GDP per Capita

1995 Growth Rates 1995 Growth Rates 1995($ Billion 1990 (1985-95) (1985-95) ($ 1000 1990 and

and PPP) (annual, %) (millions) (annual, %) PPP per person)

South Africa 172 1.1 41 2.3 4.2Egypt 156 2.2 58 2.2 2.7Algeria 84 0.3 28 2.5 3.0Nigeria 132 3.9 111 3.0 1.2Libya 25 -1.2 5 3.6 4.6Regional Total 1080 1.8 705 2.7 1.5

Primary Energy Supply Final Consumption

Total Coal Oil Gas Total Electricity

South Africa 88.9 73.6 10.8 1.7 46.3 12.3Egypt 34.7 0.6 22.2 10.9 22.8 4.5Algeria 24.3 0.5 8.0 15.8 14.1 1.2Nigeria 18.4 0.0 13.5 4.4 9.3 0.8Libya 15.8 0.0 11.7 4.0 8.7 1.5Regional Total 225.8 81.6 96.9 39.2 136.2 26.0



In order to maintain even the current low standard of living inAfrica, GDP will have to grow considerably. In the 1980s, Africa’sGDP grew less than population and so Africa had a lower GDP percapita in 1990 than in 1980. Since the early 1990s, economicperformance in Sub-Saharan Africa, the poorest sub-region of thecontinent, has improved. Growth of real GDP across the 49 countriesof Sub-Saharan Africa reached 4.3% a year from 1995 to 1997,compared with 1.5% from 1990 to 1994 and 2.5% from 1981 to19892. The assumption of regional GDP growth over the Outlookperiod, around 2.5% per annum, is similar to recent history, leading toa marginal rise in GDP per capita over the Outlook period. Theevolution of GDP in Africa is the key uncertainty for the projectionspresented here. The heavy dependence on commodity exports in manyAfrican economies makes GDP growth rates sensitive to relativelysmall shifts in world commodity prices. South Africa is sensitive tomovements in the price of coal and precious metals, and North Africaparticularly sensitive to the evolution of oil and gas prices.Furthermore, given much of Africa’s dependence on agriculture,meteorological conditions are also important. Long-term sustainedeconomic performance in the region will also largely depend oneconomic factors, such as the success of trade liberalisation, growth ofinvestment and implementation of structural reforms.

Solid Fuels36.2%

Hydro/Other 2.2%

Nuclear 1.3%

Gas17.3%

Oil42.9%

Solid Fuels31.7%

Hydro/Other 2.3%

Nuclear 0.7%

Gas23.6%

Oil41.7%

1995 2020

226 Mtoe 432 Mtoe

2. International Monetary Fund - World Economic Outlook, May 1998.


In 1995, Africa had a population of over 700 million. During thelast decade, population in Africa grew at an average of 2.7%, or morethan 16 million people every year. Clearly, demographics will be amajor determinant of future energy demand. It is assumed thatAfrican population will grow at 2.4% till 2020. Under thisassumption, the population in Africa will exceed 800 million in 2000,will pass the one billion mark shortly before 2010 and reach about 1.3billion by 2020.

Table 19.3: Assumptions for the African Region


OverviewAs shown in Table 19.4, total primary commercial energy

demand in Africa is projected to grow by an annual average of 2.6%over the Outlook period. This is slightly higher than the assumedGDP growth rate, and indicates a continuing rise in the energyintensity level. Including non-commercial biomass in the total energybalance changes the intensity trends significantly. This issue isdiscussed later in this chapter. Oil is expected to continue to dominatethe total primary energy demand mix. Coal is likely to lose somemarket share, which will be made up mainly by gas. No significantchanges in the shares of other fuel types are expected.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Coal Price ($1990 per metric ton) 44 40 42 46 0.5%Oil Price ($1990 per barrel) 6 15 17 25 2.1%GDP ($Billion 1990 and PPP) 578 1080 1560 1986 2.5%Population (millions) 366 705 1035 1279 2.4%GDP per Capita ($1000 1990 and 1.6 1.5 1.5 1.6 0.1%PPP per person)



Total final energy demand is expected to almost double by 2020,at an average annual growth rate of 2.6%. Electricity demand isprojected to grow the most rapidly. Its share in total final energydemand is expected to increase from 19% to 23% by 2020. Oil willretain a dominant share of 56% and coal’s share is likely to declineover the projection period.



Stationary Sectors Demand for energy in stationary uses is projected to rise in line

with GDP at an annual growth rate of 2.6%. Unlike many otherregions in this Outlook, the share of oil in total stationary uses isexpected to rise significantly. Within the residential/commercial

1971 1995 2010 2020 1995-2020Annual

Growth Rate


1971 1995 2010 2020 1995-2020Annual

Growth Rate



sector, a key question is the long term availability and use of non-commercial biomass energy, in particular in Sub-Saharan Africa.Because commercial fuels are still several times more expensive thantraditional fuels, it is still difficult for low-income consumers to switchto commercial energy. Given projected low income levels in theregion, the substitution of commercial for non-commercial energy isexpected to be slow. In the industrial sector, oil and gas shares areprojected to increase at the expense of coal. This is mainly due toexpected slower growth in South Africa.



0

10

20

30

40

50

60

70

80

500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 2000


mill

ion

tonn

es o

il eq

uiva

lent

Solid Fuels Oil Gas

1971 - 1995

1996 - 2020

1971 1995 2010 2020 1995-2020Annual

Growth Rate



MobilityTable 19.7 shows that demand for mobility is expected to grow at

an annual average of slightly over 2% over the Outlook period. Thisis one of the lowest expected growth rates for this sector in thedeveloping regions. Factors limiting the growth of demand formobility are both low per capita income and the poor state oftransport infrastructure.

Figure 19.4: Passenger Vehicle Ownership

Figure 19.4 shows that passenger vehicle ownership is Africancountries is extremely low, except for South Africa. Given the limitedimprovement expected in average real income levels, a substantial increasein the vehicle fleet in most of the countries in the region is unlikely.


0

10

20

30

40

50

60

70

80

90

100

South Africa Egypt Algeria Nigeria Cameroon Kenya Ethiopia

per

1000

peo

ple

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Total 19 40 56 68 2.1%




0

10

20

30

40

50

60

70

500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 2000Gross Domestic Product ($ Billion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent

1971 - 1995

1996 - 2020

0

10

20

30

40

50

60

70

500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 2000Gross Domestic Product ($ Billion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent 1971 - 1995

1996 - 2020


ElectricityAs shown in Figure 19.6, electricity demand in Africa is projected

to grow in a linear fashion with GDP. It is expected to double at anaverage growth rate of 3.4%, significantly faster than assumed forGDP.


A major reason underlying the expectation of strong growth inelectricity demand is the current low level of electrification rates inmany African countries. Only around one quarter of Africanhouseholds have access to electricity3. In South Africa, about 40% ofthe population had access to electricity in 1995 and used over half thecontinent’s electricity.

Supply

Power GenerationAfrican electricity output amounted to 367 TWh in 1995. South

Africa accounted for about half of it; the five countries of North Africa(Algeria, Egypt, Libya, Morocco, Tunisia) produced 30% of totaloutput in the region; all other countries (about 50) produced theremaining 20%.

South Africa accounted for 95% of Africa’s coal-fired generation.In the countries of North and Sub-Saharan Africa, oil, gas and hydroplants are the principal sources of electricity supply.

Electricity output in Africa is projected to grow at 3.4% per yearin the period to 2020. Coal is expected to lose market share, but willstill generate about 43% of all electricity in 2020. Currently, SouthAfrica has about 4.5 GW of excess power generation capacity4.Demand growth in the early years of the Outlook period will be metby an increase in the use of existing capacity.3. Bizuneh Fikru, African Energy Situation - Challenges and Options, paper presented at Oil andGas in Africa Conference, London 27-28 May 1998.4. ESKOM 1995 Statistical Yearbook, South Africa, 1997.

1971 1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 7 26 44 60 3.4%


Table 19.9: African Capacity (GW) and Electricity Generation (TWh)

A few other countries in the region have plans to build coal-firedplants. Egypt is planning to construct two plants: the first at AyunMusa (2x300 MW) in the Sinai Peninsula, the second at Zaferana(2x600) on the Red Sea coast. Both will also be capable of burning gas.

Natural gas use in power generation is expected to increaserapidly, faster than coal or oil; its share in the electricity output mix isprojected to rise from just under 14% in 1995 to 33% in 2020.

Currently, almost all gas-fired generation is concentrated inAlgeria, Egypt, Nigeria and Tunisia. Most of the incremental demandfor gas is likely to come from North African countries, which will tryincreasingly to substitute gas for oil in order to free up a greater quantityof oil for export or other uses. Some of the existing oil-fired plants inthese countries have already been converted to burn gas. A number ofgas-based plants are under development. Examples of such projectsinclude a 50-MW plant in Sebha, south of Tripoli; a 800-MW inZuwara on the west coast of Libya; a 400 MW plant near Tangiers; a350-450 MW plant in Kenitra in Morocco and a 2x350 MW plant atSidi Krier near Alexandria, which could also use fuel oil as a back-up fuel.

The countries in Sub-Saharan Africa are more likely to continueto use oil. Many of these countries currently use oil for powergeneration in small scale units. Given that Africa has a very poortransport infrastructure, it is unlikely that there will be a substantialshift to coal. Some generators, however, could use more gas. The shareof oil is projected to fall from 17% to 12% over the Outlook period.

The share of hydroelectric power is also expected to fall asadditions to hydroelectric capacity are made at a slower rate than thegrowth in electricity demand. Hydro capacity in 1995 was 20 GW

1995 2020Capacity Generation Capacity Generation

Solid Fuels 43 186 70 364Oil 20 63 32 104Gas 12 51 73 282Nuclear 2 11 2 12Hydro 20 56 30 84Other Renewables 0 0 2 5Total 97 367 208 848


and is assumed to grow to 30 GW by 2020. Africa, particularly Sub-Saharan Africa, has a large hydro potential, which could supply about1300 TWh per year. Current utilisation of hydropower resources isonly 4%. Poor integration of the power networks at sub-regional levellimits the development of hydro resources. Nevertheless, there areplans to link the electricity supply grids of some countries.

The 520-MW Capanda hydroelectric scheme in Angola is one ofthe largest projects. Completion is tentatively scheduled for the end ofthe century. It would double Angola’s generating capacity. There areplans to create a national grid by linking the three regional electricitysectors and establishing grid linkages with neighbouring countries.

The Sounda Gorge hydroelectric project, with a final capacity of1 GW, could make the Congo a significant regional exporter ofelectricity. Construction of the first phase is underway at the LimpopoRiver site, which will have a capacity of 10 MW. It will be used togenerate cash flow for subsequent phases. The second phase will be theconstruction of a 130-foot high dam which will boost the plant’sgenerating capacity to 240 MW. A third phase will increase the dam’sheight to over 300 feet and its generating capacity to 1 GW.Feasibility studies for the third phase are still in progress, andfinancing remains an issue.

In 1996, twelve members of the South African DevelopmentCommunity signed a co-operation agreement to develop and integratetheir hydropower and other water resources. The most important ofthe projects under this agreement is the 2040 MW Cahora Bassaproject in Mozambique. The plant was completed in the 1970s, buthas generated little electricity. With the completion of its transmissionconnections, the plant could sell power to the South African utilityESKOM.

South Africa is the only country in the region which has anynuclear generating capability. The nuclear plant at Koeberg consists oftwo 965 MW pressurised water reactors which were constructed byFramatome and are owned and operated by ESKOM. The reactorscame on line in 1984 and 1985. Given the availability of relativelycheap coal supplies and the end of South African isolation, futureexpansion of nuclear power is not expected.

Some of the North African countries have expressed interest inbuilding nuclear plants for electricity generation. It is assumed in thisstudy that none of these countries will have nuclear plants operatingbefore 2020.


There is limited use of electricity generation from renewablesources in Africa. Solar energy would seem to be an option for manycountries, particularly in rural areas, and a number of small-scaleprojects are underway, but it is likely that pricing regimes will have tochange in order to make large-scale investment and exploitationworthwhile. There is a need to create more commercial operations formaintenance, expansion and new developments.

A number of countries have significant geothermal potential:Kenya, Ethiopia and Uganda. Kenya has a small amount ofgeothermal generating capacity (45 MW) and has plans to buildadditional capacity over the next few years.

Wind turbines are already in use in several African countriesincluding Somalia, Kenya, Sudan and Cape Verde. Wind power is alsobeing considered in Egypt and Morocco.

Generation from renewable sources is assumed to grow by 11%per annum over the Outlook period. However, even with such rapidgrowth, renewable sources will continue to make a very smallcontribution to the electricity generation mix.

OilAfrica’s official oil reserves at the end of 1997 amounted to 70

billion barrels, or about 7% of the world’s official reserves5. ThreeOPEC members are the major oil producers in the region: Libya,Nigeria and Algeria with a share of 42%, 24% and 13% of totalreserves. Egypt, Angola and Gabon also have oil reserves. In 1997,total oil production in Africa reached 8.1 Mbd. The top contributorswere Nigeria at 2.4 Mbd, Libya at 1.5 Mbd, and Algeria at 1.5 Mbd.The figures include NGLs, which in the case of Algeria, amount to 0.6Mbd. Total production for these three countries averaged 5.3 Mbd in1997. Oil revenues are vital for all three countries. In 1996, the shareof oil export revenues in total exports from Algeria, Nigeria and Libyawere 75%, 97% and 95% respectively6. In the case of Algeria, most ofthe rest of the export revenues come from gas.

In 1997, non-OPEC countries in Africa produced a further 2.8million barrels per day. One third of this came from Egypt and onequarter from Angola, with small amounts of production in manyother countries, including Gabon.

As discussed in more in detail in Chapter 7, future oil production

5. Oil reserve data in this chapter come from the BP Statistical Review of World Energy 1998.6. OPEC Annual Statistical Bulletin-1996, 1997.


in Africa looks likely to remain stable up to 2010 and then start todecline. Figure 19.7 shows that, the continent is expected to remain anet oil exporter over the Outlook period. However, the export volumeis projected to decrease from 5.5 million barrels per day now to 2.2million barrels per day in 2020 as a result of a slowdown in productionlevels and increasing domestic demand.

Figure 19.7: Oil Supply and Demand

GasGas reserves in Africa are highly concentrated, with over half in

North Africa and more than one third in Nigeria. Egypt andCameroon also have significant gas reserves. Total African gas reserveswere 349 trillion cubic feet at the end of 1997, of which 131 is inAlgeria, 115 in Nigeria and 46 in Libya. Total production in theregion reached 2.2 Mtoe.

Domestic gas demand growth is projected to be around 4% perannum on average. It is driven primarily by the penetration of gas inthe power sector. Less than 20% of incremental gas demand isexpected to go to final consumption. The lack of infrastructure is themain reason for the limited contribution of gas to industry and to theresidential/commercial sectors.

0

1

2

3

4

5

6

7

8

1985 1996 2010 2020

mill

ion

barr

els

per

day

Domestic Demand Net Exports


Currently, Algeria and Libya export natural gas to Europe: Algeriavia two pipelines and as LNG, Libya using exclusively LNG. Libyacurrently exports only to Spain from the liquefaction plant at Marsa ElBrega. These exports are about 1.5 million tonnes per annum and areunlikely to increase significantly. Algeria has contracted to exportabout 37 billion cubic meters (bcm) of gas per annum to Europe,around one third via pipeline and two thirds as LNG. The mainpipeline connection, jointly owned by SNAM and Sonatrach, is theTransMed pipeline to Italy via Tunisia. This pipeline is tapped inTunisia. Its capacity is currently 14 bcm per annum, but is due shortlyto be expanded to 25 bcm per annum. Additional compressor stationswill be installed later in Algeria which will eventually give it amaximum throughput of 30 bcm per annum. The Maghreb-Europepipeline, which transports gas from Algeria via Morocco to Spain andPortugal, has a capacity of 10 bcm.

Some of the expected growth in European gas demand could bemet by supplies from North Africa in general, and Algeria inparticular. This would require investment in delivery infrastructureover and above the current de-bottlenecking of the TransMed pipeline.Algeria has embarked upon a substantial project to increase its LNGexport capacity from about 22 to 28 bcm per annum. The capacity ofthe Maghreb-Europe pipeline could be expanded to 20 bcm perannum with additional compressor stations. Total export capacitycould rise to 60 or more Gm3 per year.

Algeria also has a contract to export LNG to the United States,but the volume is relatively minor compared with the exports toEurope. Nigeria and Egypt could also become significant players inthe Mediterranean gas market in the long term.

Although primary gas demand in Africa will more than doublebetween now and 2020, this demand-side pressure should not affectthe status of North Africa as a significant gas exporter.

CoalCoal demand in Africa is almost exclusively based in South

Africa. Total recoverable reserves in South Africa are estimated to be42.2 billion tonnes. As shown in Table 19.10, South Africa producedabout 220 million tonnes (Mt) of hard coal in 1997, or 97% ofAfrican production and 5.8% of the world’s total hard coalproduction.


Table 19.10: Hard Coal Production - South Africa (Mt)

South Africa is the third largest coal exporter in the world,accounting for 13% of total world coal trade, and the second largeststeam coal exporter, accounting for 18.8% of the world steaming coaltrade in 1997. Since the completion of deregulation in 1992, noregulations or quotas have applied to coal exports. In 1997, SouthAfrica exported 63.4 Mt of hard coal (steaming coal 57.7 Mt), a riseof 6.7% on the 1996 total of 59.4 Mt. Europe took 54% of exports, afall from 59.3% in 1996. Asia took 37.1%, a rise from 34.3% in1996. South African coal is primarily exported through Richards BayCoal terminal, which has a capacity of about 60 Mt7. Further capacityexpansion is planned for completion in the near future.

Biomass

Current Patterns of Biomass Energy UseBiomass energy plays an important role in Africa. The levels of

biomass energy use in individual countries are uncertain, but it isestimated that, for the whole region, it accounts for approximately halfof total primary energy demand and 60% of total final energyconsumption8.

Africa has the second lowest average per capita GDP and the secondlowest per capita level of conventional energy consumption of all worldregions (South Asia has the lowest values). The significant differences ineconomic development, energy endowment and demography betweenNorth Africa, South Africa and Sub-Saharan Africa are also reflected inthe geographical patterns of biomass energy use, as shown in Table 19.11.

7. Energy Policies of South Africa, IEA/OECD, 1996.8. These figures and all others quoted in this section are IEA figures, obtained from a compilationof data from a large number of sources (see the IEA’s Energy Statistics and Balances of Non-OECDcountries, 1995-1996 for sources and coverage). It should be noted that Africa is the region withthe most severe problems in terms of biomass data. For example, some neighbouring countrieswith similar economical and geographical characteristics show unexplained differences in theirlevel of per capita biomass use.

1971 1980 1985 1995 1996 1997

Production 57.7 115.1 173.5 206.2 206.4 220.1Percentage of World 2.6 4.1 5.4 5.6 5.5 5.8


Sub-Saharan Africa accounts for approximately 94% of the continent’stotal final biomass consumption (205 Mtoe), but it consumes only 25%of the continent’s final conventional energy. When biomass isincorporated into the energy mix, the average per capita energyconsumption in Sub-Saharan Africa approaches a level comparable tothat in North Africa. The level in South Africa remains significantlyhigher (Figure 19.8). However, because the efficiency of use of biomassis much lower than for conventional energy, the useful energyconsumption in Sub-Saharan Africa is much lower than in other parts ofAfrica.

Figure 19.8: Average Per Capita Final Energy Use in Africa, 1995

Table 19.11: Final Biomass Energy Use in Africa, 1995

0

200

400

600

800

1000

1200

1400

North Africa Sub-Saharan South Africa

kgoe

per

cap

ita

Biomass

Conventionalenergy

Total Share of the Share of Per capita energybiomass in region’s biomass use (kgoe)

TFC (Mtoe) biomass use in TFC Biomass Conv. fuels

North Africa 3.2 2% 5% 25 443Sub-Saharan Africa 191.9 94% 86% 354 62South Africa 9.6 5% 15% 230 1118Total Africa 204.6 100% 60% 317 318


Another consequence of including biomass is that the energyintensities of the three sub-regions look significantly different, withSub-Saharan Africa showing the highest level, instead of the lowest, asit does when only conventional energy is considered (Figure 19.9).

Figure 19.9: Energy Intensity with and without Biomass, 1995

Most biomass energy in Africa is consumed in the householdsector. The share of biomass in the residential/commercial andagriculture sector is around 83% for the whole continent (16% inNorth Africa, 35% in South Africa and 93% in Sub-Saharan Africa).

Many small industrial and commercial businesses use biomass astheir main fuel9. According to IEA estimates, some 10% of biomass inSub-Saharan Africa is used in the industrial sector, accounting for 72%of the sector’s total energy consumption. In South and North Africa,about 20% of biomass is used in the industrial sector, but, because ofthe larger use of conventional fuels in these two sub-regions, the sharesof biomass in this sector are only 3% and 7%.

Firewood is the most important biomass fuel in Africa, makingup about 65% of total final biomass energy consumption. The

0

50

100

150

200

250

300

350

400

450

North Africa Sub-Saharan South Africa

toe

/ $1

000

(199

0 pr

ices

and

PPP

)

Conventional energy only

Including biomass

9. Biomass is especially important in brick making and agro-industries such as tea curing. Theservices sector also uses considerable quantities of biomass (see, among others, D.O. Hall and Y.S.Mao (eds), Biomass Energy and Coal in Africa, AFREPREN Series, Gaborone, 1994).


remainder includes crop residues, dung and charcoal. There are,however, considerable differences between urban and rural patterns ofbiomass use. The use of crop residues and dung is largely limited torural areas, while charcoal use is concentrated in urban areas where itcan account for between 40% and 90% of total biomass use. Charcoaltends to be the preferred fuel as it is easier to transport, distribute,store and use.

Much of the biomass used in rural households is collected ratherthan purchased, but in urban areas, all charcoal and a large part of thefirewood is traded. The larger the town, the greater the proportion offirewood that is traded. Fuelwood and charcoal production for theurban areas constitute important sources of employment and incomefor rural people10.

Past TrendsHistorical biomass data for African countries are scarce. Available

information suggests that, over the past 10 to 20 years, final biomassuse has increased roughly in line with population, so that per capitafinal use has remained stable, reflecting a stagnant economic situationand a lack of alternative fuels.11 There have, however, been changes inthe relative shares of the different biomass fuels, notably with shiftsfrom non-commercial to marketed biomass, in the wake of increasingurbanisation. The increasing use of charcoal in urban areas could havefar-reaching consequences: surveys carried out in Rwanda, Zambiaand Malawi indicate that, because of high charcoal use in urban areasand the poor conversion efficiencies of wood into charcoal12, urbandwellers use two to three times as much wood-equivalent per capita asdo rural people13.

ProjectionsUnder the business as usual assumptions for population and GDP

growth, and given the projected trends for conventional energy fuels,

10. Openshaw, Malawi: Biomass Energy Strategy Study, unpublished report, 1997.11. The 1995 level of GDP per capita was similar to the 1971 level and, apart from North Africa,the level of per capita final consumption of conventional fuels has also remained unchanged.12. In Africa, traditional methods of charcoal production are estimated to yield as little as 20%-25% in energy terms (see A.C. Hollingdale, R. Krishnan and A.P. Robinson, Charcoal Production,A Handbook, Natural Resource Institute, London, 1991).13. Biomass Energy and Coal in Africa, D.O. Hall and Y.S. Mao (eds), AFREPREN Series,Gaborone, 1994, and Openshaw, 1997, op.cit.


it is unlikely that biomass will diminish in importance during theOutlook period. With stagnant per capita incomes, possibly evendecreasing in some countries, and with hardly any increase in percapita usage of conventional energy, it is difficult to anticipate adecrease in per capita biomass use. As a result, it is expected that finalbiomass consumption will increase roughly at the same rate aspopulation (2.4%) between 1995 and 2020. Since final demand ofconventional energy is projected to increase at a similar rate (2.5% perannum), the share of biomass in total final energy consumption dropsonly slightly, from 60% in 1995 to 59% in 2020.


It is expected that the share of charcoal will continue to increase.Since the conversion efficiencies for charcoal production in Africa areexpected to improve only slightly, primary biomass energy will riseonly slightly faster (2.8%) than final biomass consumption.Consumption of primary conventional fuels is expected to grow at2.6%, so that the share of biomass in total final energy demand willactually increase slightly, from 50% in 1995 to 51% in 2020.

0

100

200

300

400

500

600

700

800

900

1995 2000 2005 2010 2015 2020

mill

ion

tonn

es o

il eq

uiva

lent



It is not sure that continuing high levels of biomass energy can beproduced in a sustainable way, given available resources and especiallyincreasing deforestation. Much has been written on fuelwood scarcityin Africa, but data on biomass resources and potential supply are evenmore inadequate than data on biomass consumption. Recent work14

suggests that previous assessments based on remote sensing, whichwere not accompanied by large-scale ground surveys, may have grosslyunderestimated actual and potential biomass resources. It has beennoted that many supply surveys concentrated on fuelwood, ignoringthe extensive supply of crop residues, forest residues and dung in manycountries, which can amount to as much as 30% to 40% of totalbiomass supply. Moreover, many surveys only accounted for fuelwoodfrom cut trees and branches, whereas in many countries a large part ofthe fuelwood supply consists of twigs and small branches harvestedwithout serious damage to trees.

At an aggregate level, it would appear that biomass availability inAfrica is two to four times larger than current consumption. Howeverthere are significant imbalances in the geographical distribution of theresources, both at national and sub-national level. These imbalancesand the contrast with population distribution have resulted in localisedfuel scarcity and resource degradation, especially around large towns.With continuing urbanisation, these problems are likely to increase.

14. Op. cit. in footnote 9.


Chapter 20 - Middle East 393

CHAPTER 20MIDDLE EAST1

IntroductionThis chapter presents the business as usual (BAU) projection for

the Middle East region2. The energy projections described in thischapter have been prepared using a simulation, rather than aneconometric approach, as the energy data for this region is notsufficiently robust for econometric equations to be estimated.

BackgroundThe Middle East is usually considered an energy supplier, rather

than an energy consumer. This traditional approach obscures the factthat the region’s energy demand has grown quickly in recent years andis likely to continue to do so. A rapidly growing population (the mostrapid of the ten regions considered in this Outlook) and a largeprojected increase in conventional oil production are expected to resultin energy demand expanding rapidly during the projection period. Theprinciple assumptions used in preparing the energy demandprojections for the Middle East are shown in Table 20.1.

Table 20.1: Middle East Assumptions

1. The Middle East region is defined as Bahrain, Iran, Iraq, Israel, Jordan, Kuwait, Lebanon,Oman, Qatar, Saudi Arabia, Syria, United Arab Emirates and Yemen.2. Background information on the structure of energy demand in the region is available in the1996 World Energy Outlook and in the IEA’s 1995 publication Middle East Oil and Gas.

1995 2010 2020 1995-2020Annual

Growth Rate

GDP ($Billion 1990 and PPP) 551 768 1075 2.7%Population (millions) 154 245 283 2.5%GDP per Capita ($1990 and 3578 3134 3792 0.2%PPP per person)


An interesting feature of these assumptions is that the region’sGDP and population are assumed to grow at similar rates, resulting inaverage per capita income growing by only 0.2% per annum. Aninequitable distribution of increases in GDP between the richest andpoorest sections of the population may result in energy demandincreasing less rapidly than would otherwise be the case.

The large projected increase in the region’s oil production (seeChapter 7) may produce a mixed impact on the Middle East’seconomy. Higher oil exports are likely to result in large balance ofpayments surpluses for many countries in the region, and the resultingappreciation in exchange rates could harm their non-oil industries.The United Arab Emirates is an example of an oil-exporting countrydiversifying its economy away from oil via the establishment of freetrade zones. How successful the countries in the region will be intaking this course depends, amongst other things, on how well theydeploy the large increase in oil revenues.

In many countries in the region, an informal social contract exists,whereby the general population benefits from the fact that theircountry is a large net oil exporter. Much of the benefit comes in theform of low energy prices. The subsidies reduce the profitability of theenergy distribution companies. The situation is made worse by the factthat many publicly-owned enterprises do not pay their energy bills.Subsidies not only reduce the energy prices paid by consumers, butalso result in large public sector deficits when oil prices or productionare low.

Some progress in reducing energy subsidies has occurred in recentyears. During the mid-1990s, Iran and Saudi Arabia, the two largesteconomies in the region, doubled some of their internal oil productprices in order to reduce the size of their public deficits and releaseadditional oil for export. Iran’s action followed warnings that if it didnot take action to restrain domestic oil consumption, it could cease tobe a net oil exporter by the year 20003. It has been estimated thatdoubling gasoline and diesel prices in March 1995 earned Iran anadditional $300 million in export revenues. Constraining domesticconsumption of oil products to increase oil product exports increasesthe governments’ hard currency revenue both because the volume ofexports increases and because the export price is higher than theinternal price.

3. Middle East Oil and Gas, IEA/OECD, page 106.

Another way for the region’s governments to earn additional oilexport revenues is to substitute gas for oil consumption in the internalmarket. Sectors in which this policy has been applied includehouseholds, industry and power generation. During the projectionperiod, this policy is assumed to continue. The increasing use of gas inpower stations will not only diversify the region’s fuel mix away fromoil but also promote the development of a gas network, which will, inturn, increase the possibility for gas consumption in other sectors. Thissubstitution may release heavy fuel oil, requiring an upgrade of refineryconversion capacity to convert into saleable products.

One of the main benefits of the region’s low energy prices has beenthe development of a thriving chemicals industry. Converting theregion’s substantial energy reserves into chemicals not only helps todiversify the region’s economy away from energy, and oil in particular,but also provides well-paid employment and stimulates economicdevelopment. High transport costs to the industrialised countries andtariffs, aimed at protecting the European chemicals industry, have sofar limited the chemical industry’s growth. The European Union (EU)and Gulf Cooperation Council (GCC) have discussed the possibilityof a free trade area. Were such a free trade area to come about, thenexports of chemicals from the region to the EU could increasedramatically. Such a change could significantly alter the energydemand projections and GDP assumptions presented in this chapter.


OverviewIn 1995, oil accounted for 62% of total primary energy demand

and gas made up the majority of the remaining 38%. The MiddleEast’s coal consumption is insignificant and is concentrated in powerstation use in Israel and Iran’s iron & steel industry. During theprojection period, gas demand is expected to expand rapidly at 3.7%per annum. Total gas demand will increase by around 160 Mtoe, ofwhich some 60 Mtoe will go to consuming sectors and the remainderto the secondary energy producers, primarily power generators.




Oil is likely to retain its role as the dominant fuel in TPES.Nevertheless, it is projected to account for less than 50% of TPES in2020. Oil demand will grow more slowly than the demand for anyother fuel, at just 1.7%. The current low level of non-oil demandmeans that oil only loses significant market share in the latter half ofthe projection period. Demands for coal, hydro and other renewablesare all projected to grow rapidly, but the current low levels ofconsumption of these fuels means that even by 2020 they will stillaccount for less than 1% of TPES. The general Outlook for the MiddleEast is dominated by oil and gas, but with the split between these twofuels becoming more evenly balanced.


1995 2010 2020 1995-2020Annual

Growth Rate

TPES 294 399 564 2.6%Solid Fuels 5 13 18 5.0%Oil 183 219 281 1.7%Gas 104 164 261 3.7%Hydro 1 3 3 2.9%Other Renewables 0 1 1 2.7%

1995 2010 2020 1995-2020Annual

Growth Rate

TFC 197 264 373 2.6%Coal 1 2 2 2.7%Oil 132 160 204 1.7%Gas 39 65 104 3.9%Electricity 23 37 63 4.0%Heat 0 1 1 2.7%


Total final energy consumption is projected to grow at a ratesimilar to GDP during the projection period (2.6% and 2.7%).Electricity and gas demand are both projected to grow at an annualaverage rate of around 4%. Electricity and gas infrastructures mustfirst be developed before these projected increases in demand can berealised. Finance for these developments must come either from theregion’s governments, or from private direct investment. Consumerswill have to pay market prices for these fuels that fully reflect the hugeinfrastructure investment charges required to deliver them.

Figure 20.1: Total Final Energy Consumption versus GDP (1971 - 2020)

The relatively low growth rate in final oil consumption reflects thedesire of the oil exporting countries to minimise domestic oilconsumption in order to maximise oil export revenues.

Stationary Sectors4

Energy consumption in the stationary sectors remained robustduring the decline in Middle East GDP that occurred during the1980s. In 1993, when GDP recovered to its 1979 level, total fossil fueldemand in the stationary sectors was almost twice the level in 1979. Areturn to favourable economic conditions is likely to result in

0

100

200

300

400

0 200 400 600 800 1000 1200GDP ($ Billion at 1990 prices and Purchasing Power Parities)

mill

ion

tonn

es o

il eq

uiva

lent

1971

2020

1979

1995

4. The Stationary Sectors cover all total final energy consumption except electricity and all fuels consumed in the transport sector.


continued expansion of energy demand in the stationary sectors. Thepotential for growth is large given the existing low level of energyappliance ownership.

Table 20.4: Energy Use in Stationary Sectors (Mtoe)

Figure 20.2: Energy Use in Stationary Sectors versus GDP (1971 - 2020)

Mobility


0

50

100

150

200

250

0 200 400 600 800 1000 1200


mill

ion

tonn

es o

il eq

uiva

lent

1971

1979

2020

1995

1995 2010 2020 1995-2020Annual

Growth Rate

Total 117 159 227 2.7%Solid Fuel 1 2 2 2.7%Oil 76 92 120 1.9%Gas 39 65 104 3.9%Heat 0 1 1 2.7%

1995 2010 2020 1995-2020Annual

Growth Rate

Total 56 67 84 1.6%


Total vehicle ownership in the Middle East has remained largelyunchanged in recent years, at around 100 vehicles per thousand people.Slowly rising per capita incomes will produce some increase in this levelduring the projection period, but it is unlikely that car ownership willreach, for example, OECD Europe’s level of 400 - 500 cars per thousandpeople. There are two reasons for this assumption. First, car ownershiplevels are highly dependent on income distribution. Second, women areactively discouraged from driving in some countries and this policy willinevitably limit the proportion of the population that owns cars.

Aviation fuel demand was influenced in the past by the large numberof expatriate flights to and from the region. In many countries, a policy ofreducing the number of expatriate workers has reduced aviation fuelconsumption. Increasing levels of GDP are likely to increase the numberof internal and external flights, but uncertainties exist as to the extent ofthis factor’s impact on total transport energy demand. Some modestyear-on-year growth in aviation fuel demand is likely to take place.

As with other total final consumption sectors, energy demandcontinued to grow on average in the 1980s, despite substantialreductions in GDP. As Figure 20.3 indicates, in the years leading up to1995, energy demand in the transport sector grew rapidly, at an annualaverage rate of 9.7%. Such high demand growth is consideredunsustainable and may indeed reflect data inadequacies. The region’sdemand is less than that of Germany, suggesting that a large potentialfor energy demand growth exists in the region.

Figure 20.3: Energy Demand for Mobility

0

20

40

60

80

100


mill

ion

tonn

es o

il eq

uiva

lent

1971

1995

2020

1979


Given the uncertainties of energy demand in the transport sectorand possible data problems, a cautious approach has been adopted here.Energy demand (excluding electricity) is projected to grow at a rate ofjust 1.6% during the projection period. This modest growth rate alsoreflects the desire of many governments in the region to minimisedomestic oil consumption, in order to maximise oil exports. By contrastwith other sectors, such as stationary uses and power generation, it is noteasy to switch consumption from oil to gas. It is therefore likely that apolicy of promoting oil exports will result in measures designed todiscourage excessive consumption in the region’s transport sector. Afurther factor likely to constrain consumption is the gradual removal ofgasoline and diesel price subsidies for budgetary reasons.

Electricity


Figure 20.4: Total Final Electricity Consumption

0

10

20

30

40

50

60

70


mill

ion

tonn

es o

il eq

uiva

lent

1971 1979

1995

2020

1995 2010 2020 1995-2020Annual

Growth Rate

Electricity 23 37 63 4.0%


Total final electricity consumption has been growing at over 7%in recent years, and would have gone even higher had not supplyconstraints interfered. During the projection period, electricitydemand growth is projected to moderate and grow at 4% a year.

Final consumption of electricity is projected to grow more rapidlythan for any other fuel in total final consumption.

Supply

Power GenerationElectricity generation in the Middle East grew at an average rate of

10.8% during the period 1971 to 1995, a rate even higher than inAsian regions. During the Outlook period, electricity generation isprojected to grow at a substantially lower rate of 4%, as the rate ofelectrification is expected to slow down.

The region’s electricity mix is dominated by oil and gas, which in1995 accounted for 90% of total generation. The most interestingfeature has been the switch from oil to gas-fired generation, ascountries in the region seek to free oil for export. In 1971, oilaccounted for 71% of electricity output and gas only 15%. Gas-firedpower generation grew quickly, at 16% a year between 1971 and 1995,while oil-fired generation increased by 9%. In 1995, gas-fired outputhad reached about the same level as for oil. This trend is likely tocontinue over the projection period and electricity generated from gasis expected to increase its share of output from 44% in 1995 to 60%.The share of oil-fired generation could fall to 28% by 2020.

Most of the existing power plants are steam boilers and burnheavy fuel oil, gas and crude oil, primarily for baseload use. Gasturbines and diesel engines are used for medium and peaking duty. Intotal, these plants account for about 90% of capacity. The majority ofthe Middle East’s new capacity is likely to be gas-fired. Combined-cycle gas turbines can meet the region’s increase in baseload needs butan increase in single-cycle gas turbine capacity is expected. Thepenetration of highly efficient gas turbines could boost average naturalgas generating efficiency to about 45% in 2020. Natural gasconsumption for electricity generation is projected to grow at 4.3%.By 2020, gas used in power generation could meet some 37% of totalMiddle Eastern gas demand.

Apart from building new capacity, there is a need for upgrading orconversion of a number of existing stations, by adding a steam cycle togas turbines or converting fuel oil to gas capacity.


Some countries in the region do not have gas reserves and willneed to import gas for use in power generation plants. Israel isconsidering importing natural gas via pipeline from Egypt or Russia.Prospects for importing LNG from Qatar have also been discussed.And there have been discussions on linking the electricity networks ofSyria, Turkey, Jordan and Egypt.

Table 20.7: Electricity Generation (TWh) and Capacity (GW)

Israel is the only country in the region to use coal-fired powerstations. Coal-based capacity in 1995 was 3125 MW5. The country’scoal power plants are Maor David (4x350 MW), Maor David B (575MW) and Rutenberg (2x575 MW). These are dual-fired plants whichcan burn fuel oil as well as coal, but coal is cheaper. In addition, Israelis seeking to reduce its dependence on imported oil. Coal-firedcapacity is projected to reach 11 GW by 2020.

Hydroelectric capacity in the region was about 5 GW in 1995,most of it in Iran and Syria. These two countries accounted for 93% ofhydroelectricity generation in 1993. It is assumed that another 5 GWof new hydro will be added to existing capacity by the end of theOutlook. Most of this new capacity will come from hydroelectric damscurrently under construction in Iran, including 2000 MW at Godar-e-Landar; 2000 MW at Karun-3; and 400 MW at Karkheh. Iran has thelargest untapped hydropower potential in the Middle East, estimatedat 14.7 GW conventional hydropower and 3.75 GW pumped storage.Almost all of this potential is located in the country’s mountainoussouth and southwestern regions.

In the 1970s, Iran began constructing a number of nuclear plants,with a combined capacity of 9.7 GW. Following the Iranian revolution,all these projects were abandoned. Currently, Iran has plans to complete

5. Statistical Report 1995, The Israel Electric Corporation Ltd.

1995 2020Capacity Generation Capacity Generation

Solid Fuels 3 19 11 73Oil 44 149 87 235Gas 37 144 97 499Hydro & Other Renewables 5 16 10 32Total 89 327 206 839


a 1000 MW nuclear plant at Bushehr. It is assumed that escalating costsand political difficulties will impede completion of this plant.

Some of the countries in the region are exploring the possibility ofusing renewable sources in electricity generation. Jordan has a 40 kWphotovoltaic plant and 1 MW of wind power. Wind power is alsobeing explored in Iran, where many wind turbines are already inoperation, providing electricity to 2000 homes in Manjiil and Rudbar.The Israel Electric Corporation is involved in a number of wind andsolar demonstration projects. The overall contribution of these is,however, expected to be very small over the Outlook period.

From 1971 to 1995, electricity generating capacity increased from7.6 GW to 89 GW, equivalent to an average annual growth rate of11%. Total power generation capacity in the Middle East is projectedto reach 206 GW by the end of the Outlook.

In recent years, a lack of power generation capacity has resulted inelectricity shortages in some countries in the region. The summer peakload for air conditioning places a heavy strain on available capacity,and power shortages usually occur in the summer.

Many of the countries in the region have experienced financialdifficulties in their power generation sectors because of rapid growth inelectricity demand and past pricing structures. In 1996, the SyrianMinistry of Electricity calculated that every kWh produced cost thegovernment S£3.72 (8 US cents) while consumers paid S£1.20 perkWh6.

In Saudi Arabia, power generation capacity grew at an annual rateof 14.5% from 1975 to 1996 and was largely funded by the high oilprices that continued until 1985. Lower oil prices toward the end ofthe 1980s meant the end of subsidised funds for power generation.Electricity prices are currently controlled by the government and arefar below production costs. To reduce the resulting financingdifficulties, the Saudi government introduced a surcharge of 5 Halalas(approximately 1.3 US cents) per kWh in January 1995 for monthlyconsumption in excess of 2000 kWh7. The revenue from this surchargeis deposited into a special electricity fund to help finance theconstruction of new power generation capacity.

The United Arab Emirates has also attempted to reduce itssubsidies for electricity. In 1994 electricity tariffs for expatriates (70%

6. Country Profile Syria, 1996-97, Economist Intelligence Unit, London, 1997.7. Electricity Growth & Development in the Kingdom of Saudi Arabia up to the year 1416 H(1995/1996 G), Electrical Affairs Agency, Kingdom of Saudi Arabia, 1996.


to 80% of the population) were doubled, but they were still less thanproduction costs.

Given that the power budget for many Middle East countries isoften a significant proportion of annual government expenditure, thepricing difficulties described above present electricity utilities withmajor problems. As a result, governments are increasingly forced toexamine full-cost pricing and private sector involvement. This iscurrently hindered by a number of obstacles, including:

• delays in payment for power generation schemes;• lack of market rates for electricity, which forces companies to

accept government promises on subsidies;• the need to enter into complex negotiations with the state

supplier of fossil fuels;• the possible non-purchase of electricity and the non-supply of

input fuels after the power station has been built, because of theabove contractual difficulties.

OilIn 1996, the Middle East’s total oil production8 amounted to 20.4

million barrels per day (Mbd). Of this total, about 80% was exported.As Table 20.8 shows, the percentage of Middle East oil exports isprojected to increase. By 2020, it will be about 87% of total oilproduction.

Table 20.8: Middle East Oil Balance (Mbd)

Note: This table includes all types of oil - conventional, unconventional, NGLs, etc.

Total production from the region is projected to peak at around51.8 Mbd in 2018. Unlike many other energy projections, thisOutlook does not treat the Middle East as the world’s residual oilproducer, capable of producing ever larger quantities of oil to balancedemand and supply. Instead, we project that the region’s total oil

8. This total includes both OPEC and non-OPEC production and covers all types of liquids, e.g. conventional oil, unconventional oil, NGLs, etc.

Demand Supply Net Imports

1996 4.1 20.4 -16.32010 4.9 44.7 -39.72020 6.3 49.2 -42.9


production will reach a plateau around 2014 at 51.7 Mbd and then gointo decline towards the end of the Outlook. The following chartshows how the region’s oil production is projected to be allocatedbetween domestic oil demand and exports.

Figure 20.5: Middle East Oil Balance

Note: This chart includes all types of oil - conventional, unconventional, NGLs, etc.

Gas

Table 20.9: Middle East Gas Balance (Mtoe)

Note: 1 Mtoe = 0.0429 tcf.

The region’s gas supply is projected to grow even more rapidlythan oil, at an annual average rate of 5.1%. Rising European and Asiangas demand will provide a ready market for the region’s huge gasreserves. By 2020, the percentage of the Middle East’s gas production

0

10

20

30

40

50

1996 2010 2020

mill

ion

barr

els

per

day

Production Demand Net Exports

1995 2010 2020 1995-2020Annual

Growth Rate

Demand 104 164 261 3.7%Supply 110 214 376 5.1%Net Imports -6 -50 -116 12.9%


being exported will have increased from 5% in 1995 to 31%. Gasexports from the region are projected to grow at an annual average rateof 12.9% per annum, and will earn substantial foreign exchangerevenues for the region.

Whereas oil exports are projected to be 2116 Mtoe in 2020, gasexports will be just 116 Mtoe, or 5% of oil exports. Thus, while gasexports will provide important additional revenues for the region, theywill continue to be dwarfed by the revenue earned from oil exports.The dramatic increase in the Middle East’s gas production expectedduring the projection period is shown in Figure 20.6.

Figure 20.6: Middle East Gas Production (tcf )

Comparison with Other ProjectionsApart from the IEA, two other organisations have recently

produced energy projections for the Middle East, the United StatesDepartment of Energy (USDOE)9 and the European Union (EU)10.

As is evident from Table 20.10, all three organisation project theMiddle East’s energy demand to grow at an annual average rate of

0

2

4

6

8

10

12

14

16

18

1995 2000 2005 2010 2015 2020

trilli

on c

ubic

feet

9. International Energy Outlook 1998 - With Projections Throughs 2020, USDOE/EIA-0484(98),Washington, DC, April 1998.10. European Energy to 2020 - A Scenario Approach, Energy in Europe, Special Issue - Spring 1996,Directorate General for Energy DG XVII, European Commission.


around 2.5%. Little difference exists in terms of the TPES fuel mix asindicated in Table 20.10.

Table 20.10: TPES by Fuel (Annual Growth Rates, 1995-2020)

*Note: The EU’s energy projections are actually for 1990 - 2020 and not 1995 - 2020.The USDOE projects 10 TWh of nuclear electricity in the region by 2005.

The main difference among the projections is in the rate at whichgas demand grows vis-à-vis oil demand. In both the IEA and EUenergy projections, regional gas demand grows more than twice asquickly as regional oil demand. In the USDOE projections, a greaterrole is projected for oil in the fuel mix. Some differences exist in theother fuels, but these are insignificant given the small quantities ofenergy involved. In summary, while the IEA and EU expect the shareof gas to rise rapidly during the projection period, the USDOEanticipates the share of gas to increase more modestly.

IEA EU USDOE

Solids 5.0% 4.4% 2.6%Oil 1.7% 1.3% 2.2%Gas 3.7% 3.7% 2.6%Nuclear 0.0% 0.0% -Other 2.9% 0.0% 6.7%Total 2.6% 2.3% 2.5%

Tables - Business as Usual Projection 409

PART IV

TABLESBUSINESS AS USUAL PROJECTION

Tables for the Business as Usual Projection 411

STATISTICAL NOTE

The analysis of commercial energy is based on data up to 1995,published in mid-1997. The biomass analysis used data available atend May 1998. Subsequent revisions to both commercial and biomassdata give rise to differences between energy consumption and supplyfigures for 1995 in this Outlook and those in IEA statisticalpublications of mid-1998. The IEA published for the first time in19981 historical data from 1971 to 1996 for combustible renewablesand waste for non-OECD countries. Where historical series areincomplete or unavailable, data have been estimated. The methodsused for estimation are consistent with those used for biomass in thisOutlook although, for a number of reasons, minor numericaldiscrepancies occur. The reasons include the revisions referred to aboveand the level of country disaggregation employed.


Busi

ness

as

Usu

al P

roje

ctio

n: W

orld

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

377

932

1477

1938

3.8%

3.1%

3.0%

Mob

ility

836

1520

2223

2698

2.5%

2.6%

2.3%

Foss

il fu

el &

hea

t in

Stat

iona

ry U

ses

(Ind

ustr

y,Se

rvic

es,A

gric

ultu

re,H

ouse

hold

s)24

7533

4142

2248

2410

010

010

010

01.

3%1.

6%1.

5%So

lid F

uels

757

889

1133

1305

3127

2727

0.7%

1.6%

1.5%

Oil

1102

1202

1476

1666

4536

3535

0.4%

1.4%

1.3%

Gas

549

982

1295

1489

2229

3131

2.5%

1.9%

1.7%

Hea

t67

268

318

364

38

88

6.0%

1.1%

1.2%

Tota

l Fin

al C

onsu

mpt

ion

3687

5794

7922

9461

100

100

100

100

1.9%

2.1%

2.0%

Solid

Fue

ls78

389

711

4113

1421

1514

140.

6%1.

6%1.

5%O

il18

9326

7836

3742

8551

4646

451.

5%2.

1%1.

9%G

as56

710

1913

4915

6015

1817

162.

5%1.

9%1.

7%El

ectr

icity

377

932

1477

1938

1016

1920

3.8%

3.1%

3.0%

Hea

t67

268

318

364

25

44

6.0%

1.1%

1.2%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

1269

3091

4470

5482

100

100

100

100

3.8%

2.5%

2.3%

Solid

Fue

ls61

813

6220

2325

2149

4445

463.

3%2.

7%2.

5%O

il26

830

836

741

821

108

80.

6%1.

2%1.

2%G

as24

656

510

3414

7719

1823

273.

5%4.

1%3.

9%N

ucle

ar29

608

670

604

220

1511

13.5

%0.

6%0.

0%H

ydro

104

215

296

352

87

76

3.1%

2.2%

2.0%

Oth

er R

enew

able

s4

3480

110

01

22

9.8%

6.0%

4.9%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

419

612

942

1207

1.6%

2.9%

2.8%

Solid

Fue

ls10

288

105

112

Oil

168

210

290

352

Gas

8622

733

843

1El

ectr

icity

68

202

316

411

Ren

ewab

les

00

00

Hea

t-4

-116

-108

-100

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-4

44-1

135

-179

3-2

349

Hea

t-6

2-1

50-2

08-2

61To

tal P

rim

ary

Ener

gy S

uppl

y49

8883

4111

508

1374

910

010

010

010

02.

2%2.

2%2.

0%So

lid F

uels

1503

2347

3269

3947

3028

2829

1.9%

2.2%

2.1%

Oil

2448

3324

4468

5264

4940

3938

1.3%

2.0%

1.9%

of w

hich

Inter

natio

nal M

arin

e Bun

kers:

119

129

175

209

0.3%

2.0%

1.9%

Gas

899

1810

2721

3468

1822

2425

3.0%

2.8%

2.6%

Nuc

lear

2960

867

060

41

76

413

.5%

0.6%

0.0%

Hyd

ro10

421

529

635

22

33

33.

1%2.

2%2.

0%O

ther

Ren

ewab

les

436

8311

30

01

19.

8%5.

7%4.

7%O

ther

Prim

ary

00

00

00

00

--

-

OEC

D C

ombu

stible

Ren

ewab

les an

d Wast

e (in

clude

d ab

ove)

-14

215

917

2-

21

1-

0.7%

0.8%

Non

-OEC

D C

RW (n

ot in

clude

d ab

ove)

-90

411

0812

46-

109

8-

1.4%

1.3%

Total

Prim

ary E

nerg

y Sup

ply (

inclu

ding

CRW

)-

9245

1261

614

995

-10

010

010

0-

2.1%

2.0%


Busi

ness

as

Usu

al P

roje

ctio

n: W

orld

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty24

6541

3644

6765

3679

372.

5%2.

6%2.

3%58

%Fo

ssil

fuel

in S

tatio

nary

Use

s (I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)74

2888

8386

1511

015

1263

810

010

010

010

010

00.

6%1.

7%1.

5%24

%So

lid F

uels

3132

3590

3447

4450

5142

4240

4040

410.

4%1.

7%1.

6%24

%O

il29

6630

4929

4636

7341

9540

3434

3333

0.0%

1.5%

1.4%

20%

Gas

1330

2244

2223

2891

3301

1825

2626

262.

2%1.

8%1.

6%29

%To

tal F

inal

Con

sum

ptio

n98

9213

019

1308

217

551

2057

510

010

010

010

010

01.

2%2.

0%1.

8%35

%So

lid F

uels

3233

3659

3477

4482

5176

3328

2726

250.

3%1.

7%1.

6%23

%O

il52

8870

5872

9710

050

1193

353

5456

5758

1.4%

2.2%

2.0%

42%

Gas

1372

2302

2308

3018

3467

1418

1817

172.

2%1.

8%1.

6%31

%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)364

966

7274

9811

363

1447

810

010

010

010

010

03.

0%2.

8%2.

7%70

%So

lid F

uels

2313

4598

5199

7776

9694

6369

6968

673.

4%2.

7%2.

5%69

%O

il85

510

2497

811

6713

2523

1513

109

0.6%

1.2%

1.2%

14%

Gas

481

1050

1322

2420

3458

1316

1821

244.

3%4.

1%3.

9%13

0%O

ther

Tra

nsfo

rmat

ion

810

1331

1159

1721

2133

1.5%

2.7%

2.5%

29%

Solid

Fue

ls76

153

-100

-92

-115

Oil

485

627

658

903

1092

Gas

250

551

601

910

1156

Tota

l Em

issi

ons

1473

221

400

2215

031

189

3784

810

010

010

010

010

01.

7%2.

3%2.

2%46

%So

lid F

uels

5621

8410

8576

1216

614

755

3839

3939

391.

8%2.

4%2.

2%45

%O

il70

0790

8793

4312

675

1501

248

4242

4140

1.2%

2.1%

1.9%

39%

of w

hich

Inter

natio

nal M

arin

e Bun

kers:

380

378

410

555

663

0.3%

2.0%

1.9%

47%

Gas

2103

3903

4231

6348

8081

1418

1920

213.

0%2.

7%2.

6%63

%


Busi

ness

as

Usu

al P

roje

ctio

n: W

orld

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)52

4813

204

2085

227

326

100

100

100

100

3.9%

3.1%

3.0%

Solid

Fue

ls21

3150

7779

6010

490

4138

3838

3.7%

3.0%

2.9%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:31

128

165

194

11

11

6.1%

1.7%

1.7%

Oil

1100

1315

1663

1941

2110

87

0.7%

1.6%

1.6%

Gas

691

1932

5063

8243

1315

2430

4.4%

6.6%

6.0%

Nuc

lear

111

2332

2568

2317

218

128

13.5

%0.

6%0.

0%H

ydro

1209

2498

3445

4096

2319

1715

3.1%

2.2%

2.0%

Oth

er R

enew

able

s5

4915

423

90

01

110

.0%

7.9%

6.5%

Cap

acity

(GW

)-

3079

4556

5915

-10

010

010

0-

2.6%

2.6%

Solid

Fue

ls-

1032

1362

1760

-34

3030

-1.

9%2.

2%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-25

3238

-1

11

-1.

7%1.

7%O

il-

404

527

604

-13

1210

-1.

8%1.

6%G

as-

571

1309

2035

-19

2934

-5.

7%5.

2%N

ucle

ar-

347

375

334

-11

86

-0.

5%-0

.2%

Hyd

ro-

713

940

1109

-23

2119

-1.

9%1.

8%O

ther

Ren

ewab

les

-13

4373

-0

11

-8.

5%7.

2%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

269

585

803

934

3.3%

2.1%

1.9%

Mob

ility

616

1015

1349

1479

2.1%

1.9%

1.5%

Foss

il fu

el &

hea

t in

Stat

iona

ry U

ses

(Ind

ustr

y,Se

rvic

es,A

gric

ultu

re,H

ouse

hold

s)15

4815

2516

0215

5510

010

010

010

0-0

.1%

0.3%

0.1%

Solid

Fue

ls33

623

623

524

622

1515

16-1

.5%

0.0%

0.2%

Oil

809

643

639

610

5242

4039

-1.0

%-0

.1%

-0.2

%G

as40

161

367

462

326

4042

401.

8%0.

6%0.

1%H

eat

332

5575

02

35

11.0

%3.

6%3.

5%To

tal F

inal

Con

sum

ptio

n24

3331

2537

5439

6810

010

010

010

01.

0%1.

2%1.

0%So

lid F

uels

341

236

235

246

148

66

-1.5

%0.

0%0.

2%O

il14

0216

3619

5620

5158

5252

520.

6%1.

2%0.

9%G

as41

863

570

566

117

2019

171.

8%0.

7%0.

2%El

ectr

icity

269

585

803

934

1119

2124

3.3%

2.1%

1.9%

Hea

t3

3255

750

11

211

.0%

3.6%

3.5%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

849

1751

2290

2514

100

100

100

100

3.1%

1.8%

1.5%

Solid

Fue

ls41

277

598

411

0849

4443

442.

7%1.

6%1.

4%O

il17

910

710

411

121

65

4-2

.1%

-0.2

%0.

1%G

as15

322

752

567

818

1323

271.

7%5.

7%4.

5%N

ucle

ar27

512

516

438

329

2317

13.0

%0.

0%-0

.6%

Hyd

ro74

108

121

128

96

55

1.6%

0.8%

0.7%

Oth

er R

enew

able

s4

2139

520

12

27.

6%4.

4%3.

8%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

242

308

369

388

1.0%

1.2%

0.9%

Solid

Fue

ls37

3536

38O

il89

8998

100

Gas

6888

100

94El

ectr

icity

49

101

139

160

Ren

ewab

les

00

00

Hea

t0

-5-5

-5Le

ss O

utpu

t fro

m E

lectri

city

+ C

HP

plan

tsEl

ectr

icity

-318

-686

-942

-109

4H

eat

-2-2

5-4

8-6

8To

tal P

rim

ary

Ener

gy S

uppl

y32

0444

7354

2357

071.

4%1.

3%1.

0%So

lid F

uels

790

1047

1256

1391

2523

2324

1.2%

1.2%

1.1%

Oil

1670

1832

2159

2262

5241

4040

0.4%

1.1%

0.8%

Gas

639

950

1329

1433

2021

2525

1.7%

2.3%

1.7%

Nuc

lear

2751

251

643

81

1110

813

.0%

0.0%

-0.6

%H

ydro

7410

812

112

82

22

21.

6%0.

8%0.

7%O

ther

Ren

ewab

les

423

4154

01

11

7.7%

4.1%

3.5%

Oth

er P

rimar

y0

11

10

00

0-

--

Com

busti

ble R

enew

ables

and

Was

te (in

clude

d ab

ove)

6214

215

917

22

33

33.

5%0.

7%0.

8%To

tal P

rimar

y En

ergy

Sup

ply

(inclu

ding

CRW

)32

0444

7354

2357

0710

010

010

010

01.

4%1.

3%1.

0%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty17

9427

0629

6939

4643

252.

1%1.

9%1.

5%46

%Fo

ssil

fuel

in S

tatio

nary

Use

s (I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)45

4638

1836

1137

2735

7510

010

010

010

010

0-1

.0%

0.2%

0.0%

-2%

Solid

Fue

ls14

5810

5873

072

175

032

2820

1921

-2.8

%-0

.1%

0.1%

-32%

Oil

2096

1453

1467

1453

1389

4638

4139

39-1

.5%

-0.1

%-0

.2%

0%G

as99

213

0614

1415

5314

3622

3439

4240

1.5%

0.6%

0.1%

19%

Tota

l Fin

al C

onsu

mpt

ion

6340

6524

6580

7673

7900

100

100

100

100

100

0.2%

1.0%

0.7%

18%

Solid

Fue

ls14

7710

5973

072

275

123

1611

910

-2.9

%-0

.1%

0.1%

-32%

Oil

3830

4115

4384

5327

5625

6063

6769

710.

6%1.

3%1.

0%29

%G

as10

3313

5014

6616

2515

2416

2122

2119

1.5%

0.7%

0.2%

20%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)2

327

3417

3762

5257

6088

100

100

100

100

100

2.0%

2.3%

1.9%

54%

Solid

Fue

ls14

9026

9728

9136

9841

5164

7977

7068

2.8%

1.7%

1.5%

37%

Oil

571

395

340

331

352

2512

96

6-2

.1%

-0.2

%0.

1%-1

6%G

as26

532

653

112

2715

8511

1014

2326

2.9%

5.7%

4.5%

277%

Oth

er T

rans

form

atio

n34

641

242

149

648

80.

8%1.

1%0.

6%20

%So

lid F

uels

-135

-91

-131

-134

-138

Oil

277

294

298

332

337

Gas

204

209

253

298

288

Tota

l Em

issi

ons

9013

1035

310

763

1342

714

476

100

100

100

100

100

0.7%

1.5%

1.2%

30%

Solid

Fue

ls28

3236

6434

9042

8647

6431

3532

3233

0.9%

1.4%

1.3%

17%

Oil

4678

4804

5022

5990

6315

5246

4745

440.

3%1.

2%0.

9%25

%G

as15

0318

8522

5131

5033

9717

1821

2323

1.7%

2.3%

1.7%

67%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)36

9879

7810

957

1272

110

010

010

010

03.

3%2.

1%1.

9%So

lid F

uels

1446

3138

4053

4777

3939

3738

3.3%

1.7%

1.7%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:6

115

143

164

01

11

13.0

%1.

5%1.

4%O

il80

056

255

158

522

75

5-1

.5%

-0.1

%0.

2%G

as48

810

2028

7240

4113

1326

323.

1%7.

1%5.

7%N

ucle

ar10

419

6419

7816

813

2518

1313

.0%

0.0%

-0.6

%H

ydro

855

1260

1410

1483

2316

1312

1.6%

0.8%

0.7%

Oth

er R

enew

able

s5

3493

153

00

11

8.3%

6.9%

6.2%

Cap

acity

(GW

)-

1814

2378

2752

-10

010

010

0-

1.8%

1.7%

Solid

Fue

ls-

602

642

764

-33

2728

-0.

4%1.

0%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-22

2731

-1

11

-1.

4%1.

4%O

il-

189

203

210

-10

98

-0.

5%0.

4%G

as-

342

795

1037

-19

3338

-5.

8%4.

5%N

ucle

ar-

283

282

239

-16

129

-0.

0%-0

.7%

Hyd

ro-

387

428

451

-21

1816

-0.

7%0.

6%of

whi

ch P

umpe

d St

orag

e Hyd

ro:

-75

8588

-4

43

-0.

8%0.

7%O

ther

Ren

ewab

les

-10

2952

-1

12

-7.

3%6.

9%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Eur

ope

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

9519

528

032

93.

1%2.

4%2.

1%M

obili

ty15

730

846

254

62.

8%2.

7%2.

3%Fo

ssil

fuel

& h

eat i

n St

atio

nary

Use

s(I

ndus

try,

Serv

ices

,Agr

icul

ture

,Hou

seho

lds)

636

617

661

655

100

100

100

100

-0.1

%0.

5%0.

2%So

lid F

uels

192

109

106

109

3018

1617

-2.3

%-0

.2%

0.0%

Oil

370

260

239

223

5842

3634

-1.5

%-0

.5%

-0.6

%G

as71

225

280

274

1136

4242

4.9%

1.5%

0.8%

Hea

t3

2336

480

45

79.

5%2.

9%2.

9%To

tal F

inal

Con

sum

ptio

n88

711

2014

0315

2910

010

010

010

01.

0%1.

5%1.

3%So

lid F

uels

196

109

106

109

2210

87

-2.4

%-0

.2%

0.0%

Oil

523

567

701

768

5951

5050

0.3%

1.4%

1.2%

Gas

7122

528

027

48

2020

184.

9%1.

5%0.

8%El

ectr

icity

9519

528

032

911

1720

223.

1%2.

4%2.

1%H

eat

323

3648

02

33

9.5%

2.9%

2.9%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

283

579

771

807

100

100

100

100

3.0%

1.9%

1.3%

Solid

Fue

ls15

320

825

018

454

3632

231.

3%1.

2%-0

.5%

Oil

7147

4246

258

56

-1.7

%-0

.7%

-0.1

%G

as17

5519

431

96

925

405.

1%8.

8%7.

3%N

ucle

ar13

225

225

190

539

2924

12.5

%0.

0%-0

.7%

Hyd

ro28

4250

5410

77

71.

8%1.

2%1.

0%O

ther

Ren

ewab

les

23

1014

11

12

2.1%

7.7%

6.1%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

9610

313

013

80.

3%1.

5%1.

2%So

lid F

uels

2215

1616

Oil

5736

3636

Gas

-221

3132

Elec

tric

ity

2036

5058

Ren

ewab

les

00

00

Hea

t0

-5-5

-5Le

ss O

utpu

t fro

m E

lectri

city

+ C

HP

plan

tsEl

ectr

icity

-114

-230

-330

-386

Hea

t-2

-17

-30

-42

Tota

l Pri

mar

y En

ergy

Sup

ply

1151

1554

1944

2046

100

100

100

100

1.3%

1.5%

1.1%

Solid

Fue

ls37

033

137

131

032

2119

15-0

.5%

0.8%

-0.3

%O

il65

265

077

985

057

4240

420.

0%1.

2%1.

1%G

as86

301

506

625

719

2631

5.4%

3.5%

3.0%

Nuc

lear

1322

522

519

01

1412

912

.5%

0.0%

-0.7

%H

ydro

2842

5054

23

33

1.8%

1.2%

1.0%

Oth

er R

enew

able

s2

411

160

01

12.

9%6.

3%5.

1%O

ther

Prim

ary

01

11

00

00

--

-

Com

busti

ble R

enew

ables

and

Wast

e (in

clude

d ab

ove)

1649

5765

13

33

4.8%

1.1%

1.1%

Tota

l Prim

ary

Ener

gy S

uppl

y (in

clud

ing

CRW

)115

115

5419

4420

4610

010

010

010

01.

3%1.

5%1.

1%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Eur

ope

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty46

683

291

113

6816

172.

8%2.

7%2.

3%64

%Fo

ssil

fuel

in S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)19

6915

8614

6915

3614

9510

010

010

010

010

0-1

.2%

0.3%

0.1%

-3%

Solid

Fue

ls81

554

633

632

733

941

3423

2123

-3.6

%-0

.2%

0.0%

-40%

Oil

1023

610

620

571

533

5238

4237

36-2

.1%

-0.5

%-0

.6%

-6%

Gas

131

430

513

638

624

727

3542

425.

8%1.

5%0.

8%48

%To

tal F

inal

Con

sum

ptio

n24

3424

1823

8129

0531

1210

010

010

010

010

0-0

.1%

1.3%

1.1%

20%

Solid

Fue

ls83

254

633

732

733

934

2314

1111

-3.7

%-0

.2%

0.0%

-40%

Oil

1472

1442

1531

1938

2149

6060

6467

690.

2%1.

6%1.

4%34

%G

as13

143

051

363

962

45

1822

2220

5.8%

1.5%

0.8%

48%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

890

1083

1091

1558

1576

100

100

100

100

100

0.9%

2.4%

1.5%

44%

Solid

Fue

ls62

385

881

396

968

670

7975

6244

1.1%

1.2%

-0.7

%13

%O

il22

814

214

913

414

526

1314

99

-1.7

%-0

.7%

-0.1

%-5

%G

as39

8412

945

474

54

812

2947

5.1%

8.8%

7.3%

442%

Oth

er T

rans

form

atio

n11

115

812

614

915

00.

5%1.

1%0.

7%-6

%So

lid F

uels

-64

-7-3

7-4

0-4

1O

il14

512

011

011

011

0G

as29

4553

7981

Tota

l Em

issi

ons

3435

3659

3597

4612

4839

100

100

100

100

100

0.2%

1.7%

1.2%

26%

Solid

Fue

ls13

9113

9811

1312

5798

440

3831

2720

-0.9

%0.

8%-0

.5%

-10%

Oil

1845

1703

1790

2183

2404

5447

5047

50-0

.1%

1.3%

1.2%

28%

Gas

199

559

695

1172

1451

615

1925

305.

3%3.

5%3.

0%11

0%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Eur

ope

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)13

2226

7838

3644

9210

010

010

010

03.

0%2.

4%2.

1%So

lid F

uels

557

828

997

801

4231

2618

1.7%

1.2%

-0.1

%of

which

Com

busti

ble R

enew

ables

and

Wast

e:6

3043

530

11

17.

3%2.

3%2.

3%O

il31

623

721

423

024

96

5-1

.2%

-0.7

%-0

.1%

Gas

7425

511

3120

216

1029

455.

3%10

.4%

8.6%

Nuc

lear

5186

186

372

94

3222

1612

.5%

0.0%

-0.7

%H

ydro

320

486

585

629

2418

1514

1.8%

1.2%

1.0%

Oth

er R

enew

able

s3

1046

820

01

24.

9%10

.7%

8.8%

Cap

acity

(GW

)-

628

853

1009

-10

010

010

0-

2.1%

1.9%

Solid

Fue

ls-

173

160

129

-27

1913

--0

.5%

-1.1

%of

which

Com

busti

ble R

enew

ables

and

Wast

e:-

68

10-

11

1-

2.3%

2.3%

Oil

-84

8280

-13

108

--0

.2%

-0.2

%G

as-

7527

945

9-

1233

45-

9.2%

7.5%

Nuc

lear

-12

612

710

7-

2015

11-

0.0%

-0.7

%H

ydro

-16

718

820

1-

2722

20-

0.8%

0.8%

of w

hich

Pum

ped

Stor

age H

ydro

:-

3032

34-

54

3-

0.5%

0.5%

Oth

er R

enew

able

s-

418

34-

12

3-

10.8

%9.

1%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Nor

th A

mer

ica

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

140

300

402

464

3.2%

2.0%

1.8%

Mob

ility

409

593

739

777

1.6%

1.5%

1.1%

Foss

il fu

el &

hea

t in

Stat

iona

ry U

ses

(Ind

ustr

y,Se

rvic

es,A

gric

ultu

re,H

ouse

hold

s)73

968

869

565

010

010

010

010

0-0

.3%

0.1%

-0.2

%So

lid F

uels

100

7680

8714

1111

13-1

.2%

0.3%

0.6%

Oil

317

247

249

239

4336

3637

-1.0

%0.

1%-0

.1%

Gas

322

358

354

308

4452

5147

0.4%

-0.1

%-0

.6%

Hea

t0

812

160

12

2-

3.0%

3.0%

Tota

l Fin

al C

onsu

mpt

ion

1289

1581

1836

1891

100

100

100

100

0.9%

1.0%

0.7%

Solid

Fue

ls10

076

8087

85

45

-1.2

%0.

3%0.

6%O

il70

981

995

897

855

5252

520.

6%1.

1%0.

7%G

as33

937

938

534

626

2421

180.

5%0.

1%-0

.4%

Elec

tric

ity14

030

040

246

411

1922

253.

2%2.

0%1.

8%H

eat

08

1216

00

11

-3.

0%3.

0%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)47

692

711

8313

2010

010

010

010

02.

8%1.

6%1.

4%So

lid F

uels

233

498

648

830

4954

5563

3.2%

1.8%

2.1%

Oil

5817

2427

122

22

-5.0

%2.

1%1.

8%G

as13

513

225

427

128

1421

21-0

.1%

4.5%

2.9%

Nuc

lear

1221

218

211

42

2315

912

.8%

-1.0

%-2

.4%

Hyd

ro37

5658

608

65

51.

8%0.

3%0.

3%O

ther

Ren

ewab

les

113

1818

01

11

14.6

%2.

0%1.

4%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

126

165

192

198

1.1%

1.0%

0.7%

Solid

Fue

ls5

89

10O

il22

3744

45G

as74

6566

60El

ectr

icity

25

5372

83R

enew

able

s0

00

0H

eat

01

11

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-1

66-3

53-4

74-5

47H

eat

0-8

-12

-16

Tota

l Pri

mar

y En

ergy

Sup

ply

1724

2312

2724

2846

100

100

100

100

1.2%

1.1%

0.8%

Solid

Fue

ls33

858

273

792

720

2527

332.

3%1.

6%1.

9%O

il78

987

310

2510

5046

3838

370.

4%1.

1%0.

7%G

as54

857

670

567

632

2526

240.

2%1.

4%0.

6%N

ucle

ar12

212

182

114

19

74

12.8

%-1

.0%

-2.4

%H

ydro

3756

5860

22

22

1.8%

0.3%

0.3%

Oth

er R

enew

able

s1

1318

180

11

114

.6%

2.0%

1.4%

Oth

er P

rimar

y0

00

00

00

0-

--

Com

busti

ble R

enew

ables

and

Wast

e(in

clude

d abo

ve)

4381

8792

24

33

2.7%

0.5%

0.5%

Tota

l Prim

ary

Ener

gy S

uppl

y (in

cludi

ng C

RW)

1724

2312

2724

2846

100

100

100

100

1.2%

1.1%

0.8%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Nor

th A

mer

ica

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty11

8115

8317

2021

4222

501.

6%1.

5%1.

1%35

%Fo

ssil

fuel

in S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)20

6916

7315

5815

6414

5310

010

010

010

010

0-1

.2%

0.0%

-0.3

%-6

%So

lid F

uels

449

305

191

202

221

2218

1213

15-3

.5%

0.3%

0.6%

-34%

Oil

776

547

534

538

515

3733

3434

35-1

.5%

0.1%

-0.1

%-2

%G

as84

582

183

382

571

741

4953

5349

-0.1

%-0

.1%

-0.6

%0%

Tota

l Fin

al C

onsu

mpt

ion

3250

3255

3278

3706

3703

100

100

100

100

100

0.0%

0.8%

0.5%

14%

Solid

Fue

ls44

930

519

120

222

114

96

56

-3.5

%0.

3%0.

6%-3

4%O

il19

1520

8722

0326

0826

7759

6467

7072

0.6%

1.1%

0.8%

25%

Gas

885

864

883

896

805

2727

2724

220.

0%0.

1%-0

.4%

4%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)115

418

5221

5430

4238

0010

010

010

010

010

02.

6%2.

3%2.

3%64

%So

lid F

uels

744

1596

1791

2373

3082

6486

8378

813.

7%1.

9%2.

2%49

%O

il18

799

5576

8616

53

32

-4.9

%2.

1%1.

8%-2

3%G

as22

315

730

859

363

319

814

1917

1.3%

4.5%

2.9%

277%

Oth

er T

rans

form

atio

n23

923

226

729

227

80.

5%0.

6%0.

2%26

%So

lid F

uels

-46

-23

-28

-29

-32

Oil

113

124

140

164

168

Gas

173

131

154

157

142

Tota

l Em

issi

ons

4643

5339

5699

7041

7781

100

100

100

100

100

0.9%

1.4%

1.3%

32%

Solid

Fue

ls11

4718

7819

5525

4632

7125

3534

3642

2.2%

1.8%

2.1%

36%

Oil

2215

2310

2399

2849

2931

4843

4240

380.

3%1.

2%0.

8%23

%G

as12

8111

5113

4516

4615

8028

2224

2320

0.2%

1.4%

0.6%

43%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Nor

th A

mer

ica

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)19

2541

1055

0863

6310

010

010

010

03.

2%2.

0%1.

8%So

lid F

uels

805

1983

2650

3536

4248

4856

3.8%

2.0%

2.3%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:0

6780

880

21

126

.1%

1.2%

1.1%

Oil

242

9813

415

113

22

2-3

.7%

2.1%

1.8%

Gas

407

551

1319

1500

2113

2424

1.3%

6.0%

4.1%

Nuc

lear

4581

269

743

72

2013

712

.8%

-1.0

%-2

.4%

Hyd

ro42

664

868

070

322

1612

111.

8%0.

3%0.

3%O

ther

Ren

ewab

les

119

2936

00

11

15.6

%2.

9%2.

6%C

apac

ity (G

W)

-91

211

5913

17-

100

100

100

-1.

6%1.

5%So

lid F

uels

-37

241

856

4-

4136

43-

0.8%

1.7%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:-

1215

16-

11

1-

1.2%

1.1%

Oil

-45

5158

-5

44

-0.

9%1.

0%G

as-

209

415

450

-23

3634

-4.

7%3.

1%N

ucle

ar-

116

9659

-13

84

--1

.2%

-2.7

%H

ydro

-16

517

217

7-

1815

13-

0.3%

0.3%

of w

hich

Pum

ped

Stor

age H

ydro

:-

2222

22-

22

2-

0.0%

0.0%

Oth

er R

enew

able

s-

57

10-

11

1-

2.1%

2.4%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Pac

ific

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

3490

122

141

4.1%

2.0%

1.8%

Mob

ility

5011

414

815

53.

5%1.

7%1.

2%Fo

ssil

fuel

& h

eat i

n St

atio

nary

Use

s(I

ndus

try,

Serv

ices

,Agr

icul

ture

,Hou

seho

lds)

173

220

246

251

100

100

100

100

1.0%

0.8%

0.5%

Solid

Fue

ls44

5249

4925

2420

200.

7%-0

.3%

-0.2

%O

il12

113

615

014

970

6261

590.

5%0.

6%0.

4%G

as8

3039

414

1416

165.

9%1.

8%1.

3%H

eat

01

812

01

35

-12

.0%

8.9%

Tota

l Fin

al C

onsu

mpt

ion

257

424

516

547

100

100

100

100

2.1%

1.3%

1.0%

Solid

Fue

ls45

5249

4917

1210

90.

6%-0

.3%

-0.2

%O

il17

125

029

830

466

5958

561.

6%1.

2%0.

8%G

as8

3039

413

78

85.

9%1.

8%1.

2%El

ectr

icity

3490

122

141

1321

2426

4.1%

2.0%

1.8%

Hea

t0

18

120

01

2-

12.0

%8.

9%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)90

245

336

387

100

100

100

100

4.3%

2.1%

1.8%

Solid

Fue

ls27

7087

9430

2926

244.

1%1.

4%1.

2%O

il49

4338

3955

1811

10-0

.6%

-0.8

%-0

.4%

Gas

241

7789

217

2323

14.4

%4.

3%3.

1%N

ucle

ar2

7610

913

42

3132

3516

.2%

2.4%

2.3%

Hyd

ro9

1112

1310

44

30.

6%1.

0%0.

8%O

ther

Ren

ewab

les

14

1219

12

35

5.8%

7.1%

6.3%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

2040

4851

2.9%

1.2%

1.0%

Solid

Fue

ls11

1211

11O

il9

1518

19G

as-4

22

2El

ectr

icity

5

1217

19R

enew

able

s0

00

0H

eat

00

-1-1

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-3

9-1

02-1

39-1

60H

eat

00

-6-1

0To

tal P

rim

ary

Ener

gy S

uppl

y32

960

775

581

510

010

010

010

02.

6%1.

5%1.

2%So

lid F

uels

8213

414

815

425

2220

192.

1%0.

7%0.

6%O

il22

930

935

436

170

5147

441.

2%0.

9%0.

6%G

as5

7311

913

22

1216

1611

.6%

3.3%

2.4%

Nuc

lear

276

109

134

113

1416

16.2

%2.

4%2.

3%H

ydro

911

1213

32

22

0.6%

1.0%

0.8%

Oth

er R

enew

able

s1

513

200

12

26.

7%6.

2%5.

6%O

ther

Prim

ary

00

00

00

00

--

-

Com

busti

ble R

enew

ables

and

Was

te (in

clude

d ab

ove)

412

1416

12

22

5.3%

1.0%

1.0%

Tota

l Prim

ary

Ener

gy S

uppl

y (in

clud

ing

CRW

)32

960

775

581

510

010

010

010

02.

6%1.

5%1.

2%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Pac

ific

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty14

829

133

843

645

93.

5%1.

7%1.

2%50

%Fo

ssil

fuel

in S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)50

856

058

362

762

710

010

010

010

010

00.

6%0.

5%0.

3%12

%So

lid F

uels

194

207

202

192

191

3837

3531

300.

2%-0

.3%

-0.2

%-7

%O

il29

829

631

334

434

159

5354

5554

0.2%

0.6%

0.4%

16%

Gas

1756

6990

943

1012

1415

6.1%

1.8%

1.3%

61%

Tota

l Fin

al C

onsu

mpt

ion

656

850

921

1062

1085

100

100

100

100

100

1.4%

1.0%

0.7%

25%

Solid

Fue

ls19

720

820

219

219

130

2422

1818

0.1%

-0.3

%-0

.2%

-7%

Oil

443

586

650

780

799

6769

7173

741.

6%1.

2%0.

8%33

%G

as17

5669

9095

37

88

96.

1%1.

8%1.

2%60

%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)28

348

251

765

771

110

010

010

010

010

02.

5%1.

6%1.

3%36

%So

lid F

uels

122

243

286

356

383

4350

5554

543.

6%1.

5%1.

2%47

%O

il15

615

413

512

112

155

3226

1817

-0.6

%-0

.8%

-0.4

%-2

2%G

as4

8595

181

207

118

1827

2914

.4%

4.3%

3.1%

112%

Oth

er T

rans

form

atio

n-4

2328

5560

-4.

5%3.

1%14

0%So

lid F

uels

-25

-61

-66

-64

-65

Oil

1950

4857

59G

as2

3446

6266

Tota

l Em

issi

ons

935

1355

1466

1774

1856

100

100

100

100

100

1.9%

1.3%

0.9%

31%

Solid

Fue

ls29

438

942

348

451

031

2929

2727

1.5%

0.9%

0.8%

24%

Oil

618

791

833

958

979

6658

5754

531.

2%0.

9%0.

7%21

%G

as22

175

211

333

367

213

1419

209.

8%3.

1%2.

2%90

%


Busi

ness

as

Usu

al P

roje

ctio

n: O

ECD

Pac

ific

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)45

111

9016

1318

6510

0%10

010

010

04.

1%2.

0%1.

8%So

lid F

uels

8432

740

644

119

2725

245.

8%1.

5%1.

2%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

018

2123

01

11

19.2

%1.

0%1.

0%O

il24

222

720

320

454

1913

11-0

.3%

-0.8

%-0

.4%

Gas

721

442

251

92

1826

2815

.1%

4.6%

3.6%

Nuc

lear

829

141

851

52

2426

2816

.2%

2.4%

2.3%

Hyd

ro10

912

614

515

224

119

80.

6%1.

0%0.

8%O

ther

Ren

ewab

les

15

1835

00

12

6.2%

8.5%

7.8%

Cap

acity

(GW

)-

274

366

426

-10

010

010

0-

2.0%

1.8%

Solid

Fue

ls-

5765

71-

2118

17-

0.8%

0.9%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:-

45

5-

11

1-

1.0%

1.0%

Oil

-60

6973

-22

1917

-1.

0%0.

8%G

as-

5810

112

8-

2128

30-

3.7%

3.2%

Nuc

lear

-41

5973

-15

1617

-2.

4%2.

3%H

ydro

-56

6973

-21

1917

-1.

4%1.

1%of

whi

ch P

umpe

d St

orag

e Hyd

ro:

-23

3033

-8

88

-1.

9%1.

4%O

ther

Ren

ewab

les

-1

49

-0

12

-10

.7%

10.2

%


Busi

ness

as

Usu

al P

roje

ctio

n: T

rans

ition

Eco

nom

ies

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

6610

216

923

31.

8%3.

4%3.

4%M

obili

ty10

077

120

162

-1.1

%3.

0%3.

0%Fo

ssil

fuel

& h

eat i

n St

atio

nary

Use

s(I

ndus

try,

Serv

ices

,Agr

icul

ture

,Hou

seho

lds)

540

661

787

900

100

100

100

100

0.8%

1.2%

1.2%

Solid

Fue

ls20

610

911

912

038

1615

13-2

.6%

0.6%

0.4%

Oil

150

117

142

165

2818

1818

-1.0

%1.

3%1.

4%G

as12

021

931

139

922

3339

442.

6%2.

4%2.

4%H

eat

6421

621

621

612

3327

245.

2%0.

0%0.

0%To

tal F

inal

Con

sum

ptio

n70

684

010

7712

9510

010

010

010

00.

7%1.

7%1.

7%So

lid F

uels

216

109

119

121

3113

119

-2.8

%0.

6%0.

4%O

il24

018

124

029

634

2222

23-1

.2%

1.9%

2.0%

Gas

120

232

332

428

1728

3133

2.8%

2.4%

2.5%

Elec

tric

ity66

102

169

233

912

1618

1.8%

3.4%

3.4%

Hea

t64

216

216

216

926

2017

5.2%

0.0%

0.0%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

289

536

625

693

100

100

100

100

2.6%

1.0%

1.0%

Solid

Fue

ls14

316

421

021

250

3134

310.

6%1.

7%1.

0%O

il48

6350

5017

128

71.

1%-1

.4%

-0.9

%G

as83

228

267

351

2943

4351

4.3%

1.1%

1.7%

Nuc

lear

257

6748

111

117

16.1

%1.

2%-0

.7%

Hyd

ro13

2529

325

55

52.

7%1.

1%1.

0%O

ther

Ren

ewab

les

00

00

00

00

-0.

0%0.

0%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

8816

4059

-6.8

%6.

1%5.

2%So

lid F

uels

4627

2726

Oil

3331

3844

Gas

438

4856

Elec

tric

ity

1037

4450

Ren

ewab

les

00

00

Hea

t-4

-117

-117

-117

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-7

7-1

40-2

14-2

842.

5%2.

9%2.

9%H

eat

-60

-99

-99

-99

2.1%

0.0%

0.0%

Tota

l Pri

mar

y En

ergy

Sup

ply

946

1154

1429

1664

100

100

100

100

0.8%

1.4%

1.5%

Solid

Fue

ls40

530

035

736

043

2625

22-1

.2%

1.2%

0.7%

Oil

321

275

329

390

3424

2323

-0.6

%1.

2%1.

4%G

as20

649

864

783

522

4345

503.

7%1.

8%2.

1%N

ucle

ar2

5767

480

55

316

.1%

1.2%

-0.7

%H

ydro

1325

2932

12

22

2.7%

1.1%

1.0%

Oth

er R

enew

able

s0

00

00

00

0-

-2.5

%-1

.5%

Oth

er P

rimar

y-1

-1-1

-10

00

0-

--

Com

busti

ble R

enew

ables

and

Wast

e (no

t inc

lude

d ab

ove)

-27

2829

-2

22

-0.

3%0.

3%To

tal P

rimar

y En

ergy

Sup

ply

(incl

udin

g C

RW)

-11

8114

5716

93-

100

100

100

-1.

4%1.

5%


Busi

ness

as

Usu

al P

roje

ctio

n: T

rans

ition

Eco

nom

ies

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty30

745

622

134

446

4-1

.4%

3.0%

3.0%

-25%

Foss

il fu

el S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)15

4019

9912

7815

9218

5610

010

010

010

010

0-0

.8%

1.5%

1.5%

-20%

Solid

Fue

ls81

868

047

351

752

553

3437

3228

-2.3

%0.

6%0.

4%-2

4%O

il45

061

530

737

042

929

3124

2323

-1.6

%1.

3%1.

3%-4

0%G

as27

270

449

870

490

218

3539

4449

2.6%

2.3%

2.4%

0%To

tal F

inal

Con

sum

ptio

n18

4724

5514

9919

3623

2010

010

010

010

010

0-0

.9%

1.7%

1.8%

-21%

Solid

Fue

ls85

469

647

552

052

946

2832

2723

-2.4

%0.

6%0.

4%-2

5%O

il71

910

4149

766

382

039

4233

3435

-1.5

%1.

9%2.

0%-3

6%G

as27

371

852

875

397

115

2935

3942

2.8%

2.4%

2.5%

5%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)92

416

6813

9516

3718

3810

010

010

010

010

01.

7%1.

1%1.

1%-2

%So

lid F

uels

577

847

658

847

853

6251

4752

460.

5%1.

7%1.

0%0%

Oil

154

259

202

161

158

1716

1410

91.

1%-1

.5%

-1.0

%-3

8%G

as19

356

253

562

982

821

3438

3845

4.3%

1.1%

1.8%

12%

Oth

er T

rans

form

atio

n25

830

324

127

930

7-0

.3%

1.0%

1.0%

-8%

Solid

Fue

ls15

872

7168

61O

il91

101

8310

111

8G

as10

131

8710

912

8To

tal C

O2

Emis

sion

s30

2944

2631

3538

5244

6510

010

010

010

010

00.

1%1.

4%1.

4%-1

3%So

lid F

uels

1589

1614

1204

1435

1443

5236

3837

32-1

.2%

1.2%

0.7%

-11%

Oil

964

1401

781

926

1095

3232

2524

25-0

.9%

1.1%

1.4%

-34%

Gas

476

1411

1150

1491

1927

1632

3739

433.

7%1.

7%2.

1%6%


Busi

ness

as

Usu

al P

roje

ctio

n: T

rans

ition

Eco

nom

ies

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)97

316

3124

9132

9810

010

010

010

02.

2%2.

9%2.

9%So

lid F

uels

481

498

703

770

4931

2823

0.1%

2.3%

1.8%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:23

33

32

00

0-8

.4%

0.0%

0.0%

Oil

158

140

156

179

169

65

-0.5

%0.

7%1.

0%G

as17

648

710

3617

9318

3042

544.

3%5.

2%5.

4%N

ucle

ar6

216

257

181

113

105

16.0

%1.

2%-0

.7%

Hyd

ro15

229

034

037

516

1814

112.

7%1.

1%1.

0%O

ther

Ren

ewab

les

00

00

00

00

-0.

0%0.

0%C

apac

ity (G

W)

-43

458

677

6-

100

100

100

-2.

0%2.

3%So

lid F

uels

-13

715

014

5-

3226

19-

0.6%

0.2%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:-

11

1-

00

0-

0.0%

0.0%

Oil

-49

6066

-11

108

-1.

4%1.

2%G

as-

120

237

431

-28

4056

-4.

6%5.

3%N

ucle

ar-

4144

29-

98

4-

0.5%

-1.4

%H

ydro

-88

9510

4-

2016

13-

0.6%

0.7%

Oth

er R

enew

able

s-

00

0-

00

0-

0.0%

0.0%


Busi

ness

as

Usu

al P

roje

ctio

n: C

hina

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

1068

165

255

8.2%

6.0%

5.4%

Mob

ility

659

130

190

10.3

%5.

4%4.

8%Fo

ssil

fuel

& h

eat i

n St

atio

nary

Use

s(I

ndus

try,

Serv

ices

,Agr

icul

ture

,Hou

seho

lds)

179

521

850

1079

100

100

100

100

4.5%

3.3%

3.0%

Solid

Fue

ls14

740

961

074

882

7872

694.

4%2.

7%2.

4%O

il31

8015

721

317

1519

204.

0%4.

6%4.

0%G

as1

1336

471

24

49.

6%7.

0%5.

2%H

eat

019

4671

04

57

-5.

9%5.

3%To

tal F

inal

Con

sum

ptio

n19

564

911

4515

2410

010

010

010

05.

1%3.

9%3.

5%So

lid F

uels

147

416

617

755

7564

5450

4.4%

2.7%

2.4%

Oil

3713

228

039

519

2024

265.

5%5.

1%4.

5%G

as1

1336

471

23

39.

6%7.

0%5.

2%El

ectr

icity

1068

165

255

511

1417

8.2%

6.0%

5.4%

Hea

t0

1946

710

34

5-

5.9%

5.3%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

3727

556

782

510

010

010

010

08.

7%5.

0%4.

5%So

lid F

uels

3024

145

964

882

8881

799.

0%4.

4%4.

0%O

il4

1336

5511

56

75.

0%6.

8%5.

8%G

as0

112

240

02

3-

20.7

%14

.9%

Nuc

lear

03

1933

01

34

-12

.2%

9.6%

Hyd

ro3

1639

627

67

88.

0%6.

0%5.

5%O

ther

Ren

ewab

les

00

23

00

00

--

-


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

1955

122

178

4.5%

5.4%

4.8%

Solid

Fue

ls13

711

13O

il2

1839

55G

as2

38

10El

ectr

icity

2

2150

77R

enew

able

s0

00

0H

eat

06

1422

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-1

2-8

9-2

15-3

32H

eat

0-2

6-6

1-9

4To

tal P

rim

ary

Ener

gy S

uppl

y23

986

415

5921

0110

010

010

010

05.

5%4.

0%3.

6%So

lid F

uels

190

664

1087

1416

8077

7067

5.3%

3.3%

3.1%

Oil

4316

435

550

618

1923

245.

7%5.

3%4.

6%G

as3

1757

811

24

47.

2%8.

5%6.

5%N

ucle

ar0

319

330

01

2-

12.2

%9.

6%H

ydro

316

3962

12

33

8.0%

6.0%

5.5%

Oth

er R

enew

able

s0

02

30

00

0-

--

Oth

er P

rimar

y0

00

00

00

0-

--

Com

busti

ble R

enew

ables

and

Wast

e (no

t inc

lude

d ab

ove)

-20

621

622

4-

1912

10-

0.3%

0.3%

Tota

l Prim

ary E

nerg

y Sup

ply (

inclu

ding

CRW

)-

1070

1775

2325

-10

010

010

0-

3.4%

3.2%


Busi

ness

as

Usu

al P

roje

ctio

n: C

hina

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty16

142

180

389

564

10.5

%5.

3%4.

7%17

4%Fo

ssil

fuel

in S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)67

515

0618

9329

5536

8210

010

010

010

010

04.

4%3.

0%2.

7%96

%So

lid F

uels

578

1318

1682

2508

3072

8688

8985

834.

5%2.

7%2.

4%90

%O

il93

168

190

391

538

1411

1013

153.

0%4.

9%4.

2%13

3%G

as3

2021

5672

01

12

27.

9%6.

9%5.

1%18

0%To

tal F

inal

Con

sum

ptio

n69

216

4820

7333

4442

4610

010

010

010

010

04.

7%3.

2%2.

9%10

3%So

lid F

uels

578

1359

1709

2536

3099

8482

8276

734.

6%2.

7%2.

4%87

%O

il11

026

834

475

210

7416

1617

2225

4.9%

5.4%

4.7%

181%

Gas

320

2156

720

11

22

8.0%

6.8%

5.1%

176%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

132

607

982

1930

2753

100

100

100

100

100

8.7%

4.6%

4.2%

218%

Solid

Fue

ls11

855

693

817

8725

2390

9295

9392

9.0%

4.4%

4.0%

221%

Oil

1349

4311

417

510

84

66

4.9%

6.8%

5.8%

135%

Gas

02

229

550

00

12

-20

.7%

14.9

%13

95%

Oth

er T

rans

form

atio

n52

156

-448

83-

--

-70%

Solid

Fue

ls42

106

-75

-111

-136

Oil

543

5712

016

9G

as4

814

3850

Tota

l Em

issi

ons

875

2411

3051

5322

7081

100

100

100

100

100

5.3%

3.8%

3.4%

121%

Solid

Fue

ls73

920

2125

7242

1254

8684

8484

7977

5.3%

3.3%

3.1%

108%

Oil

128

360

443

987

1418

1515

1519

205.

3%5.

5%4.

8%17

4%G

as7

3036

123

177

11

12

36.

9%8.

5%6.

5%31

2%


Busi

ness

as

Usu

al P

roje

ctio

n: C

hina

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)14

410

3624

9738

5710

010

010

010

08.

6%6.

0%5.

4%So

lid F

uels

9976

717

2926

1269

7469

688.

9%5.

6%5.

0%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

00

01

00

00

--

-O

il15

6316

825

710

67

76.

2%6.

8%5.

8%G

as0

265

123

00

33

-24

.6%

17.1

%N

ucle

ar0

1372

127

01

33

-12

.2%

9.6%

Hyd

ro30

191

457

726

2118

1819

8.0%

6.0%

5.5%

Oth

er R

enew

able

s0

07

110

00

0-

--

Cap

acity

(GW

)-

227

501

757

-10

010

010

0-

5.4%

4.9%

Solid

Fue

ls-

158

323

472

-70

6462

-4.

9%4.

5%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-0

00

-0

00

-21

.7%

14.7

%O

il-

1330

45-

66

6-

5.7%

5.1%

Gas

-1

1018

-0

22

-17

.5%

12.8

%N

ucle

ar-

211

20-

12

3-

11.6

%9.

3%H

ydro

-52

125

199

-23

2526

-6.

0%5.

5%O

ther

Ren

ewab

les

-0

34

-0

11

-16

.7%

11.9

%


Busi

ness

as

Usu

al P

roje

ctio

n: R

est o

f the

Wor

ld*

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

3117

633

951

67.

5%4.

4%4.

4%M

obili

ty11

436

962

586

85.

0%3.

6%3.

5%Fo

ssil

fuel

& h

eat i

n St

atio

nary

Use

s(I

ndus

try,

Serv

ices

,Agr

icul

ture

,Hou

seho

lds)

207

634

982

1290

100

100

100

100

4.8%

3.0%

2.9%

Solid

Fue

ls68

135

169

191

3321

1715

2.9%

1.5%

1.4%

Oil

112

362

538

678

5457

5553

5.0%

2.7%

2.5%

Gas

2813

727

442

113

2228

336.

9%4.

7%4.

6%H

eat

00

11

00

00

-2.

1%2.

7%To

tal F

inal

Con

sum

ptio

n35

211

7919

4526

7510

010

010

010

05.

2%3.

4%3.

3%So

lid F

uels

8013

516

919

123

119

72.

2%1.

5%1.

4%O

il21

472

911

6015

4361

6260

585.

2%3.

1%3.

0%G

as28

139

276

424

812

1416

7.0%

4.7%

4.6%

Elec

tric

ity31

176

339

516

915

1719

7.5%

4.4%

4.4%

Hea

t0

01

10

00

0-

2.1%

2.7%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

9453

098

914

5110

010

010

010

07.

5%4.

3%4.

1%So

lid F

uels

3318

236

955

435

3437

387.

4%4.

8%4.

5%O

il37

124

177

202

3923

1814

5.2%

2.4%

2.0%

Gas

1010

822

942

410

2023

2910

.5%

5.1%

5.6%

Nuc

lear

036

6886

07

76

21.5

%4.

3%3.

5%H

ydro

1565

106

130

1612

119

6.4%

3.3%

2.8%

Oth

er R

enew

able

s0

1339

550

24

427

.9%

7.7%

6.0%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

6923

241

158

35.

2%3.

9%3.

8%So

lid F

uels

619

3136

Oil

4471

114

153

Gas

1398

183

271

Elec

tric

ity

643

8312

4R

enew

able

s0

00

0H

eat

00

00

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-3

7-2

19-4

22-6

40H

eat

00

00

Tota

l Pri

mar

y En

ergy

Sup

ply

479

1721

2923

4068

100

100

100

100

5.5%

3.6%

3.5%

Solid

Fue

ls11

933

757

078

125

2019

194.

4%3.

6%3.

4%O

il29

592

414

5118

9761

5450

474.

9%3.

0%2.

9%G

as51

346

688

1119

1120

2428

8.3%

4.7%

4.8%

Nuc

lear

036

6886

02

22

21.5

%4.

3%3.

5%H

ydro

1565

106

130

34

43

6.4%

3.3%

2.8%

Oth

er R

enew

able

s0

1340

560

11

128

.1%

7.6%

5.9%

Oth

er P

rimar

y0

00

00

00

0-

--

Com

busti

ble R

enew

ables

and

Wast

e (no

t inc

lude

d ab

ove)

-67

186

399

3-

2823

20-

1.7%

1.6%

Tota

l Prim

ary

Ener

gy S

uppl

y (in

clud

ing

CRW

)-

2392

3787

5061

-10

010

010

0-

3.1%

3.0%

* So

uth

Asi

a, E

ast

Asi

a, L

atin

Am

eric

a, A

fric

a an

d M

iddl

e E

ast.


Busi

ness

as

Usu

al P

roje

ctio

n: R

est o

f the

Wor

ld*

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty34

783

210

9618

5725

844.

9%3.

6%3.

5%12

3%Fo

ssil

fuel

in S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)66

715

6118

3427

4035

2510

010

010

010

010

04.

3%2.

7%2.

6%76

%So

lid F

uels

278

534

562

704

795

4234

3126

233.

0%1.

5%1.

4%32

%O

il32

781

398

214

5818

3949

5254

5352

4.7%

2.7%

2.5%

79%

Gas

6221

429

057

989

29

1416

2125

6.6%

4.7%

4.6%

171%

Tota

l Fin

al C

onsu

mpt

ion

1014

2393

2930

4597

6109

100

100

100

100

100

4.5%

3.0%

3.0%

92%

Solid

Fue

ls32

354

556

370

579

632

2319

1513

2.3%

1.5%

1.4%

29%

Oil

629

1634

2073

3308

4414

6268

7172

725.

1%3.

2%3.

1%10

2%G

as62

214

294

584

899

69

1013

156.

7%4.

7%4.

6%17

3%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)26

798

013

5925

3937

9910

010

010

010

010

07.

0%4.

3%4.

2%16

1%So

lid F

uels

127

499

712

1444

2167

4851

5257

577.

4%4.

8%4.

6%19

0%O

il11

732

139

456

064

144

3329

2217

5.2%

2.4%

2.0%

74%

Gas

2316

025

353

599

19

1619

2227

10.5

%5.

1%5.

6%24

4%O

ther

Tra

nsfo

rmat

ion

155

460

502

898

1255

5.0%

4.0%

3.7%

95%

Solid

Fue

ls11

6735

8498

Oil

111

190

220

350

467

Gas

3220

324

746

469

0To

tal E

mis

sion

s14

3638

3347

9180

3411

163

100

100

100

100

100

5.1%

3.5%

3.4%

110%

Solid

Fue

ls46

111

1013

1022

3330

6232

2927

2827

4.4%

3.6%

3.5%

101%

Oil

857

2146

2687

4218

5522

6056

5652

494.

9%3.

1%2.

9%97

%G

as11

757

779

415

8325

808

1517

2023

8.3%

4.7%

4.8%

174%

* So

uth

Asi

a, E

ast

Asi

a, L

atin

Am

eric

a, A

fric

a an

d M

iddl

e E

ast.


Busi

ness

as

Usu

al P

roje

ctio

n: R

est o

f the

Wor

ld*

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)43

225

5949

0874

5010

010

010

010

07.

7%4.

4%4.

4%So

lid F

uels

104

674

1475

2331

2426

3031

8.1%

5.4%

5.1%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:2

1019

261

00

06.

3%4.

2%3.

9%O

il12

855

078

892

030

2116

126.

3%2.

4%2.

1%G

as27

423

1090

2286

617

2231

12.1

%6.

5%7.

0%N

ucle

ar1

139

262

328

05

54

21.5

%4.

3%3.

5%H

ydro

171

758

1238

1511

4030

2520

6.4%

3.3%

2.8%

Oth

er R

enew

able

s0

1554

750

11

1-

8.9%

6.6%

Cap

acity

(GW

)-

605

1091

1630

-10

010

010

0-

4.0%

4.0%

Solid

Fue

ls-

135

248

379

-22

2323

-4.

2%4.

2%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-2

46

-0

00

-4.

2%3.

9%O

il-

154

235

283

-25

2217

-2.

9%2.

5%G

as-

108

267

549

-18

2434

-6.

2%6.

7%N

ucle

ar-

2138

47-

33

3-

4.1%

3.3%

Hyd

ro-

185

292

355

-31

2722

-3.

1%2.

6%O

ther

Ren

ewab

les

-3

1216

-0

11

-10

.9%

7.8%

* So

uth

Asi

a, E

ast

Asi

a, L

atin

Am

eric

a, A

fric

a an

d M

iddl

e E

ast.


Busi

ness

as

Usu

al P

roje

ctio

n: E

ast A

sia

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

542

9014

19.

1%5.

2%4.

9%M

obili

ty19

9520

531

37.

0%5.

3%4.

9%Fo

ssil

fuel

& h

eat i

n St

atio

nary

Use

s(I

ndus

try,

Serv

ices

,Agr

icul

ture

,Hou

seho

lds)

5517

928

235

910

010

010

010

05.

1%3.

1%2.

8%So

lid F

uels

3047

5457

5526

1916

1.8%

0.9%

0.8%

Oil

2411

318

323

143

6365

646.

8%3.

3%2.

9%G

as1

1945

712

1116

2013

.0%

5.8%

5.4%

Hea

t0

00

00

00

0-

--

Tota

l Fin

al C

onsu

mpt

ion

7931

657

781

310

010

010

010

06.

0%4.

1%3.

8%So

lid F

uels

3047

5457

3915

97

1.8%

0.9%

0.8%

Oil

4220

838

854

353

6667

676.

9%4.

2%3.

9%G

as1

1945

711

68

913

.0%

5.8%

5.4%

Elec

tric

ity5

4290

141

713

1617

9.1%

5.2%

4.9%

Hea

t0

00

00

00

0-

--

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

1513

629

143

610

010

010

010

09.

7%5.

2%4.

8%So

lid F

uels

334

8715

718

2530

3611

.0%

6.6%

6.4%

Oil

1035

4543

6526

1610

5.6%

1.6%

0.7%

Gas

027

6510

92

2022

2521

.2%

6.0%

5.7%

Nuc

lear

027

5370

020

1816

-4.

7%3.

9%H

ydro

27

1116

145

44

5.0%

3.5%

3.5%

Oth

er R

enew

able

s0

729

420

510

10-

10.1

%7.

5%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

864

133

201

9.0%

5.0%

4.7%

Solid

Fue

ls1

45

5O

il6

2038

53G

as0

2969

109

Elec

tric

ity

110

2133

Ren

ewab

les

00

00

Hea

t0

00

0Le

ss O

utpu

t fro

m E

lectri

city

+ C

HP

plan

tsEl

ectr

icity

-6-5

2-1

11-1

75H

eat

00

00

Tota

l Pri

mar

y En

ergy

Sup

ply

9546

489

012

7510

010

010

010

06.

8%4.

4%4.

1%So

lid F

uels

3484

145

219

3618

1617

3.8%

3.7%

3.9%

Oil

5826

447

263

960

5753

506.

5%3.

9%3.

6%G

as1

7617

928

91

1620

2318

.5%

5.9%

5.5%

Nuc

lear

027

5370

06

65

-4.

7%3.

9%H

ydro

27

1116

21

11

5.0%

3.5%

3.5%

Oth

er R

enew

able

s0

729

420

13

3-

10.1

%7.

5%O

ther

Prim

ary

00

00

00

00

--

-

Com

busti

ble R

enew

ables

and

Wast

e (no

t inc

lude

d ab

ove)

-11

712

913

6-

2013

10-

0.7%

0.6%

Tota

l Prim

ary E

nerg

y Sup

ply (

inclu

ding

CRW

)-

581

1018

1411

-10

010

010

0-

3.8%

3.6%


Busi

ness

as

Usu

al P

roje

ctio

n: E

ast A

sia

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty55

185

282

611

931

7.0%

5.3%

4.9%

230%

Foss

il fu

el S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)19

142

150

975

593

610

010

010

010

010

04.

2%2.

7%2.

5%79

%So

lid F

uels

119

209

205

236

251

6250

4031

272.

3%1.

0%0.

8%13

%O

il70

195

278

453

576

3746

5560

625.

9%3.

3%3.

0%13

3%G

as2

1726

6610

81

45

912

11.0

%6.

3%5.

8%28

1%To

tal F

inal

Con

sum

ptio

n24

660

779

213

6618

6710

010

010

010

010

05.

0%3.

7%3.

5%12

5%So

lid F

uels

120

209

205

236

251

4934

2617

132.

3%1.

0%0.

8%13

%O

il12

538

056

110

6415

0851

6371

7881

6.5%

4.4%

4.0%

180%

Gas

217

2666

108

13

35

611

.0%

6.3%

5.8%

282%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

4220

530

863

810

0710

010

010

010

010

08.

6%5.

0%4.

9%21

0%So

lid F

uels

1195

132

343

618

2546

4354

6111

.1%

6.6%

6.4%

260%

Oil

3186

113

144

135

7342

3723

135.

6%1.

6%0.

7%67

%G

as1

2463

151

254

112

2124

2521

.2%

6.0%

5.7%

533%

Oth

er T

rans

form

atio

n19

8713

429

445

08.

4%5.

4%5.

0%24

0%So

lid F

uels

42

-7-8

-9O

il15

3258

108

151

Gas

152

8319

430

8To

tal E

mis

sion

s30

889

912

3322

9833

2510

010

010

010

010

06.

0%4.

2%4.

0%15

6%So

lid F

uels

134

307

330

571

860

4434

2725

263.

8%3.

7%3.

9%86

%O

il17

049

873

113

1617

9455

5559

5754

6.3%

4.0%

3.7%

164%

Gas

394

173

412

670

110

1418

2017

.9%

6.0%

5.6%

339%


Busi

ness

as

Usu

al P

roje

ctio

n: E

ast A

sia

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)72

608

1294

2030

100

100

100

100

9.3%

5.2%

4.9%

Solid

Fue

ls9

140

377

705

1323

2935

12.1

%6.

8%6.

7%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

00

12

00

00

-5.

5%7.

1%O

il38

175

223

210

5229

1710

6.6%

1.6%

0.7%

Gas

110

532

461

42

1725

3020

.9%

7.8%

7.3%

Nuc

lear

010

220

526

70

1716

13-

4.7%

3.9%

Hyd

ro24

7813

118

534

1310

95.

0%3.

5%3.

5%O

ther

Ren

ewab

les

08

3449

01

32

-10

.1%

7.5%

Cap

acity

(GW

)-

126

275

432

-10

010

010

0-

5.3%

5.1%

Solid

Fue

ls-

2357

106

-18

2125

-6.

4%6.

4%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-0

01

-0

00

-5.

5%7.

1%O

il-

4164

66-

3323

15-

2.9%

1.9%

Gas

-21

7916

0-

1729

37-

9.2%

8.5%

Nuc

lear

-14

2837

-11

108

-4.

7%3.

9%H

ydro

-25

4055

-20

1513

-3.

1%3.

2%O

ther

Ren

ewab

les

-1

69

-1

22

-10

.1%

7.5%


Busi

ness

as

Usu

al P

roje

ctio

n: S

outh

Asi

a

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

531

6910

78.

0%5.

4%5.

0%M

obili

ty17

4692

141

4.3%

4.7%

4.5%

Foss

il fu

el &

hea

t in

Stat

iona

ry U

ses

(Ind

ustr

y,Se

rvic

es,A

gric

ultu

re,H

ouse

hold

s)33

110

200

275

100

100

100

100

5.2%

4.1%

3.7%

Solid

Fue

ls17

5070

8152

4635

304.

6%2.

2%1.

9%O

il14

4176

102

4237

3837

4.6%

4.3%

3.7%

Gas

219

5592

617

2733

10.1

%7.

3%6.

5%H

eat

00

00

00

00

--

-To

tal F

inal

Con

sum

ptio

n55

188

362

523

100

100

100

100

5.3%

4.5%

4.2%

Solid

Fue

ls25

5070

8146

2719

163.

0%2.

2%1.

9%O

il23

8716

824

242

4646

465.

7%4.

5%4.

2%G

as2

1955

923

1015

1810

.1%

7.3%

6.5%

Elec

tric

ity5

3169

107

917

1921

8.0%

5.4%

5.0%

Hea

t0

00

00

00

0-

--

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

1712

324

436

310

010

010

010

08.

7%4.

7%4.

4%So

lid F

uels

1093

182

262

6275

7572

9.6%

4.6%

4.2%

Oil

27

1422

116

66

5.8%

4.7%

4.7%

Gas

112

2654

810

1115

9.7%

5.5%

6.3%

Nuc

lear

02

45

22

21

7.6%

4.6%

3.7%

Hyd

ro3

1017

2017

87

55.

3%3.

9%2.

9%O

ther

Ren

ewab

les

00

11

00

00

-38

.8%

22.9

%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

815

4568

2.9%

7.5%

6.2%

Solid

Fue

ls3

-34

5O

il3

59

14G

as0

39

14El

ectr

icity

2

1023

35R

enew

able

s0

00

0H

eat

00

00

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-7

-42

-92

-142

Hea

t0

00

0To

tal P

rim

ary

Ener

gy S

uppl

y72

284

558

811

100

100

100

100

5.9%

4.6%

4.3%

Solid

Fue

ls39

140

256

348

5349

4643

5.5%

4.1%

3.7%

Oil

2799

191

277

3835

3434

5.5%

4.5%

4.2%

Gas

334

9016

05

1216

2010

.2%

6.7%

6.4%

Nuc

lear

02

45

01

11

7.6%

4.6%

3.7%

Hyd

ro3

1017

204

33

25.

3%3.

9%2.

9%O

ther

Ren

ewab

les

00

11

00

00

-38

.8%

22.9

%O

ther

Prim

ary

00

00

00

00

--

-

Com

busti

ble R

enew

ables

and

Wast

e (no

t inc

luded

abov

e)-

244

285

308

-46

3428

-1.

0%0.

9%To

tal P

rimar

y Ene

rgy S

uppl

y (in

cludi

ng C

RW)

-52

884

411

19-

100

100

100

-3.

2%3.

0%


Busi

ness

as

Usu

al P

roje

ctio

n: S

outh

Asi

a

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty57

101

141

280

427

3.8%

4.7%

4.5%

177%

Foss

il fu

el in

Sta

tiona

ry U

ses

(Ind

ustr

y,Ser

vice

s,Agr

icul

ture

,Hou

seho

lds)

109

297

358

617

820

100

100

100

100

100

5.1%

3.7%

3.4%

108%

Solid

Fue

ls68

182

200

277

323

6361

5645

394.

6%2.

2%1.

9%52

%O

il37

8411

521

829

134

2832

3535

4.9%

4.3%

3.8%

158%

Gas

431

4312

320

64

1012

2025

10.3

%7.

3%6.

5%30

2%To

tal F

inal

Con

sum

ptio

n16

739

849

989

712

4710

010

010

010

010

04.

7%4.

0%3.

7%12

5%So

lid F

uels

9919

220

027

732

360

4840

3126

3.0%

2.2%

1.9%

45%

Oil

6317

625

649

771

838

4451

5558

6.0%

4.5%

4.2%

183%

Gas

431

4312

320

62

89

1417

10.3

%7.

3%6.

5%30

2%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)49

257

410

813

1213

100

100

100

100

100

9.2%

4.7%

4.4%

216%

Solid

Fue

ls40

220

360

707

1018

8286

8887

849.

5%4.

6%4.

2%22

1%O

il6

1622

4469

126

55

65.

8%4.

7%4.

7%16

9%G

as3

2028

6212

66

87

810

9.7%

5.5%

6.3%

202%

Oth

er T

rans

form

atio

n18

304

6896

-5.8

%20

.3%

13.3

%12

7%So

lid F

uels

109

-17

2124

Oil

718

1427

39G

as0

37

2034

Tota

l Em

issi

ons

233

685

913

1777

2556

100

100

100

100

100

5.8%

4.5%

4.2%

160%

Solid

Fue

ls15

042

154

410

0513

6564

6160

5753

5.5%

4.2%

3.8%

139%

Oil

7621

029

256

782

533

3132

3232

5.8%

4.5%

4.2%

171%

Gas

754

7720

536

63

88

1214

10.3

%6.

7%6.

4%27

8%


Busi

ness

as

Usu

al P

roje

ctio

n: S

outh

Asi

a

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)76

485

1070

1657

100

100

100

100

8.0%

5.4%

5.0%

Solid

Fue

ls32

288

661

1026

4259

6262

9.5%

5.7%

5.2%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:0

05

70

00

0-

--

Oil

630

6096

76

66

7.3%

4.7%

4.8%

Gas

448

126

277

510

1217

10.8

%6.

7%7.

3%N

ucle

ar1

815

192

21

17.

6%4.

6%3.

7%H

ydro

3311

220

022

943

2319

145.

3%3.

9%2.

9%O

ther

Ren

ewab

les

00

810

00

11

--

-C

apac

ity (G

W)

-10

621

230

4-

100

100

100

-4.

7%4.

3%So

lid F

uels

-53

109

161

-50

5153

-5.

0%4.

6%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-0

12

-0

01

-14

.6%

10.5

%O

il-

1115

20-

107

6-

2.2%

2.4%

Gas

-15

3563

-14

1721

-5.

9%5.

9%N

ucle

ar-

23

4-

22

1-

3.5%

2.7%

Hyd

ro-

2646

53-

2422

17-

3.9%

2.9%

Oth

er R

enew

able

s-

04

5-

02

1-

--


Busi

ness

as

Usu

al P

roje

ctio

n: L

atin

Am

eric

a

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

1253

9814

46.

4%4.

2%4.

1%M

obili

ty51

131

204

263

4.0%

3.0%

2.8%

Foss

il fu

el &

hea

t in

Stat

iona

ry U

ses

(Ind

ustr

y,Se

rvic

es,A

gric

ultu

re,H

ouse

hold

s)64

158

238

298

100

100

100

100

3.8%

2.8%

2.6%

Solid

Fue

ls5

1619

218

108

75.

0%1.

1%1.

2%O

il47

9312

714

673

5953

492.

9%2.

1%1.

8%G

as12

4992

131

1931

3944

5.9%

4.3%

4.0%

Hea

t0

00

00

00

0-

--

Tota

l Fin

al C

onsu

mpt

ion

127

342

540

706

100

100

100

100

4.2%

3.1%

2.9%

Solid

Fue

ls5

1619

214

53

34.

8%1.

1%1.

2%O

il98

224

329

407

7765

6158

3.5%

2.6%

2.4%

Gas

1250

9413

410

1517

196.

0%4.

4%4.

0%El

ectr

icity

1253

9814

49

1618

206.

4%4.

2%4.

1%H

eat

00

00

00

00

--

-El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)32

114

215

317

100

100

100

100

5.5%

4.3%

4.2%

Solid

Fue

ls2

824

365

711

116.

9%7.

4%6.

1%O

il16

3257

6751

2827

212.

9%3.

9%2.

9%G

as6

2149

112

2018

2335

5.0%

5.9%

7.0%

Nuc

lear

05

88

04

42

-3.

4%2.

0%H

ydro

843

6984

2437

3227

7.5%

3.3%

2.8%

Oth

er R

enew

able

s0

68

100

54

323

.6%

2.1%

2.1%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

3561

104

141

2.3%

3.6%

3.4%

Solid

Fue

ls1

11

1O

il23

2638

46G

as9

2242

60El

ectr

icity

2

1223

34R

enew

able

s0

00

0H

eat

00

00

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-1

4-6

6-1

21-1

78H

eat

00

00

Tota

l Pri

mar

y En

ergy

Sup

ply

181

452

738

986

100

100

100

100

3.9%

3.3%

3.2%

Solid

Fue

ls8

2544

595

66

64.

8%3.

8%3.

5%O

il13

728

142

452

076

6257

533.

0%2.

8%2.

5%G

as28

9318

530

615

2025

315.

2%4.

7%4.

9%N

ucle

ar0

58

80

11

1-

3.4%

2.0%

Hyd

ro8

4369

844

99

97.

5%3.

3%2.

8%O

ther

Ren

ewab

les

06

810

01

11

23.6

%2.

1%2.

1%O

ther

Prim

ary

00

00

00

00

--

-

Com

busti

ble R

enew

ables

and

Wast

e(no

t inc

luded

abov

e)-

8391

95-

1611

9-

0.6%

0.5%

Tota

l Prim

ary E

nerg

y Sup

ply (

inclu

ding

CRW

)-

535

829

1081

-10

010

010

0-

3.0%

2.8%


Busi

ness

as

Usu

al P

roje

ctio

n: L

atin

Am

eric

a

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty15

131

638

860

377

84.

0%3.

0%2.

8%91

%Fo

ssil

fuel

in S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)18

936

942

862

877

710

010

010

010

010

03.

5%2.

6%2.

4%70

%So

lid F

uels

2255

6678

9012

1516

1212

4.7%

1.1%

1.2%

43%

Oil

139

229

252

343

394

7462

5955

512.

5%2.

1%1.

8%50

%G

as28

8510

920

729

415

2326

3338

5.9%

4.3%

4.0%

143%

Tota

l Fin

al C

onsu

mpt

ion

339

685

816

1231

1555

100

100

100

100

100

3.7%

2.8%

2.6%

80%

Solid

Fue

ls23

5566

7890

78

86

64.

6%1.

1%1.

2%43

%O

il28

954

563

894

211

6685

8078

7775

3.4%

2.6%

2.4%

73%

Gas

2885

111

211

300

812

1417

196.

0%4.

4%4.

0%14

7%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)74

155

185

394

621

100

100

100

100

100

3.9%

5.2%

5.0%

154%

Solid

Fue

ls7

2234

9914

89

1518

2524

6.9%

7.4%

6.1%

341%

Oil

5294

103

181

212

7160

5646

342.

9%3.

9%2.

9%94

%G

as15

3948

113

262

2025

2629

425.

0%5.

9%7.

0%19

3%O

ther

Tra

nsfo

rmat

ion

8213

513

422

029

12.

1%3.

4%3.

1%64

%So

lid F

uels

22

-1-2

-2O

il58

8683

122

151

Gas

2247

5310

014

2To

tal E

mis

sion

s49

597

411

3518

4524

6710

010

010

010

010

03.

5%3.

3%3.

2%89

%So

lid F

uels

3279

9917

623

56

89

1010

4.8%

3.9%

3.5%

123%

Oil

400

725

824

1245

1528

8174

7367

623.

1%2.

8%2.

5%72

%G

as64

171

212

425

704

1318

1923

295.

1%4.

7%4.

9%14

9%


Busi

ness

as

Usu

al P

roje

ctio

n: L

atin

Am

eric

a

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)16

677

214

0920

7310

010

010

010

06.

6%4.

1%4.

0%So

lid F

uels

742

109

163

45

88

7.6%

6.5%

5.6%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te:2

1013

171

11

16.

2%2.

1%2.

3%O

il54

134

236

275

3317

1713

3.8%

3.9%

2.9%

Gas

1776

222

613

1010

1630

6.5%

7.4%

8.7%

Nuc

lear

018

3030

02

21

-3.

4%2.

1%H

ydro

8749

580

398

053

6457

477.

5%3.

3%2.

8%O

ther

Ren

ewab

les

07

911

01

11

23.6

%2.

3%2.

2%C

apac

ity (G

W)

-18

732

648

0-

100

100

100

-3.

8%3.

8%So

lid F

uels

-13

2131

-7

66

-3.

1%3.

5%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-2

34

-1

11

-2.

7%2.

7%O

il-

3867

78-

2021

16-

3.9%

2.9%

Gas

-23

6315

7-

1219

33-

6.9%

8.0%

Nuc

lear

-3

44

-2

11

-3.

0%1.

8%H

ydro

-10

917

020

7-

5852

43-

3.0%

2.6%

Oth

er R

enew

able

s-

12

2-

11

0-

3.8%

3.1%


Busi

ness

as

Usu

al P

roje

ctio

n: A

fric

a

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

726

4460

5.6%

3.6%

3.4%

Mob

ility

1940

5668

3.2%

2.2%

2.1%

Foss

il fu

el &

hea

t in

Stat

iona

ry U

ses

(Ind

ustr

y,Se

rvic

es,A

gric

ultu

re,H

ouse

hold

s)31

7010

213

210

010

010

010

03.

4%2.

6%2.

6%So

lid F

uels

1621

2529

5029

2522

1.1%

1.4%

1.4%

Oil

1539

6080

4855

5960

4.0%

3.0%

2.9%

Gas

111

1723

215

1717

13.0

%3.

1%3.

1%H

eat

00

00

00

00

--

-To

tal F

inal

Con

sum

ptio

n57

136

202

260

100

100

100

100

3.7%

2.7%

2.6%

Solid

Fue

ls19

2126

2933

1513

110.

4%1.

4%1.

4%O

il30

7811

514

753

5757

564.

0%2.

6%2.

6%G

as1

1118

231

89

913

.3%

2.9%

2.9%

Elec

tric

ity7

2644

6012

1922

235.

6%3.

6%3.

4%H

eat

00

00

00

00

--

-El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)23

8013

117

110

010

010

010

05.

3%3.

3%3.

1%So

lid F

uels

1844

6583

7855

5049

3.8%

2.7%

2.6%

Oil

313

2122

1216

1613

6.6%

3.4%

2.2%

Gas

015

3453

219

2631

16.6

%5.

4%5.

1%N

ucle

ar0

33

30

42

2-

0.5%

0.3%

Hyd

ro2

56

79

65

43.

8%1.

6%1.

6%O

ther

Ren

ewab

les

00

23

00

12

-12

.6%

8.9%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

441

5974

10.3

%2.

4%2.

4%So

lid F

uels

017

2124

Oil

16

911

Gas

212

1926

Elec

tric

ity

15

913

Ren

ewab

les

00

00

Hea

t0

00

0Le

ss O

utpu

t fro

m E

lectri

city

+ C

HP

plan

tsEl

ectr

icity

-8-3

2-5

3-7

3H

eat

00

00

Tota

l Pri

mar

y En

ergy

Sup

ply

7622

633

943

210

010

010

010

04.

6%2.

7%2.

6%So

lid F

uels

3782

112

137

4936

3332

3.4%

2.1%

2.1%

Oil

3497

145

180

4543

4342

4.4%

2.7%

2.5%

Gas

339

7010

23

1721

2412

.1%

4.0%

3.9%

Nuc

lear

03

33

01

11

-0.

5%0.

3%H

ydro

25

67

32

22

3.8%

1.6%

1.6%

Oth

er R

enew

able

s0

02

30

01

1-

12.6

%8.

9%O

ther

Prim

ary

00

00

00

00

--

-

Com

busti

ble R

enew

ables

and

Wast

e (no

t inc

lude

d ab

ove)

-22

535

745

3-

5051

51-

3.1%

2.8%

Tota

l Prim

ary

Ener

gy S

uppl

y (in

clud

ing

CRW

)-

451

696

886

-10

010

010

0-

2.9%

2.7%


Busi

ness

as

Usu

al P

roje

ctio

n: A

fric

a

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty58

109

118

164

199

3.0%

2.2%

2.1%

50%

Foss

il fu

el &

hea

t in

Stat

iona

ry U

ses

(Ind

ustr

y,Ser

vice

s,Agr

icul

ture

,Hou

seho

lds)

113

202

218

309

388

100

100

100

100

100

2.8%

2.4%

2.3%

53%

Solid

Fue

ls67

8487

106

122

5942

4034

311.

1%1.

4%1.

4%27

%O

il45

102

110

168

219

4050

5054

563.

8%2.

9%2.

8%65

%G

as1

1622

3547

18

1011

1214

.0%

3.1%

3.1%

112%

Tota

l Fin

al C

onsu

mpt

ion

171

312

336

473

587

100

100

100

100

100

2.9%

2.3%

2.3%

52%

Solid

Fue

ls79

8587

107

122

4627

2623

210.

4%1.

4%1.

4%26

%O

il91

211

226

330

416

5368

6770

713.

9%2.

6%2.

5%57

%G

as1

1623

3648

15

78

814

.3%

2.9%

2.9%

119%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

7921

324

639

851

710

010

010

010

010

04.

8%3.

3%3.

0%87

%So

lid F

uels

7015

117

025

332

388

7169

6362

3.8%

2.7%

2.6%

67%

Oil

938

4167

7011

1816

1714

6.6%

3.4%

2.2%

79%

Gas

124

3679

124

111

1520

2416

.6%

5.4%

5.1%

232%

Oth

er T

rans

form

atio

n1

9911

015

018

522

.0%

2.1%

2.1%

51%

Solid

Fue

ls-6

5460

7485

Oil

212

2029

37G

as4

3431

4763

Tota

l Em

issi

ons

251

624

693

1022

1290

100

100

100

100

100

4.3%

2.6%

2.5%

64%

Solid

Fue

ls14

329

031

743

353

157

4746

4241

3.4%

2.1%

2.1%

49%

Oil

102

260

286

427

524

4142

4142

414.

4%2.

7%2.

5%64

%G

as6

7490

162

235

212

1316

1812

.0%

4.0%

3.9%

119%


Busi

ness

as

Usu

al P

roje

ctio

n: A

fric

a

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)91

367

622

851

100

100

100

100

6.0%

3.6%

3.4%

Solid

Fue

ls56

186

278

364

6251

4543

5.1%

2.7%

2.7%

of w

hich

Com

busti

ble R

enew

ables

and

Was

te is

00

11

00

00

6.0%

5.7%

3.4%

Oil

1163

9910

412

1716

127.

7%3.

1%2.

0%G

as1

5115

828

21

1425

3317

.7%

7.9%

7.1%

Nuc

lear

011

1212

03

21

-0.

5%0.

3%H

ydro

2356

7284

2515

1210

3.8%

1.6%

1.6%

Oth

er R

enew

able

s0

03

50

01

1-

15.5

%10

.8%

Cap

acity

(GW

)-

9715

220

8-

100

100

100

-3.

0%3.

1%So

lid F

uels

-43

5370

-44

3533

-1.

4%1.

9%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste

is-

00

0-

00

0-

0.0%

0.0%

Oil

-20

3032

-20

2016

-2.

9%2.

0%G

as-

1240

73-

1227

35-

8.4%

7.5%

Nuc

lear

-2

22

-2

11

-0.

0%0.

0%H

ydro

-20

2630

-21

1715

-1.

6%1.

6%O

ther

Ren

ewab

les

-0

11

-0

11

-21

.1%

14.2

%


Busi

ness

as

Usu

al P

roje

ctio

n: M

iddl

e Ea

st

ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esD

eman

d fo

r En

ergy

Rel

ated

Ser

vice

s (E

RS)

Elec

tric

ity (f

inal

dem

and)

223

3763

10.7

%3.

2%4.

0%M

obili

ty9

5667

848.

1%1.

2%1.

6%Fo

ssil

fuel

& h

eat i

n St

atio

nary

Use

s(I

ndus

try,

Serv

ices

,Agr

icul

ture

,Hou

seho

lds)

2411

715

922

710

010

010

010

06.

8%2.

1%2.

7%So

lid F

uels

01

22

21

11

4.8%

2.1%

2.7%

Oil

1276

9212

050

6558

537.

9%1.

3%1.

9%G

as12

3965

104

4834

4146

5.2%

3.4%

3.9%

Hea

t0

01

10

00

0-

2.1%

2.7%

Tota

l Fin

al C

onsu

mpt

ion

3519

726

437

310

010

010

010

07.

5%2.

0%2.

6%So

lid F

uels

01

22

11

11

4.8%

2.1%

2.7%

Oil

2113

216

020

460

6760

558.

0%1.

3%1.

7%G

as12

3965

104

3420

2528

5.2%

3.4%

3.9%

Elec

tric

ity2

2337

636

1214

1710

.7%

3.2%

4.0%

Hea

t0

01

10

00

0-

2.1%

2.7%

Elec

tric

ity G

ener

atio

n (in

cl. C

HP

Plan

ts)

876

109

164

100

100

100

100

9.9%

2.4%

3.1%

Solid

Fue

ls0

411

160

510

10-

6.7%

5.5%

Oil

637

3949

7649

3630

7.9%

0.4%

1.2%

Gas

234

5696

2044

5159

13.5

%3.

4%4.

3%N

ucle

ar0

00

00

00

0-

--

Hyd

ro0

13

34

23

26.

1%4.

9%2.

9%O

ther

Ren

ewab

les

00

00

00

00

-6.

5%5.

5%


ENER

GY

BAL

ANC

E19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

mill

ion

tonn

es o

il eq

uiva

lent

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esO

ther

Tra

nsfo

rmat

ion

1450

7098

5.4%

2.2%

2.7%

Solid

Fue

ls0

00

0O

il12

1420

28G

as2

3144

61El

ectr

icity

0

57

9R

enew

able

s0

00

0H

eat

00

00

Less

Out

put f

rom

Elec

tricit

y +

CH

P pl

ants

Elec

tric

ity-2

-28

-44

-72

Hea

t0

00

0To

tal P

rim

ary

Ener

gy S

uppl

y55

295

399

564

100

100

100

100

7.3%

2.0%

2.6%

Solid

Fue

ls0

513

181

23

311

.7%

5.9%

5.0%

Oil

3818

321

928

170

6255

506.

7%1.

2%1.

7%G

as16

104

164

261

2935

4146

8.2%

3.1%

3.7%

Nuc

lear

00

00

00

00

--

-H

ydro

01

33

10

10

6.1%

4.9%

2.9%

Oth

er R

enew

able

s0

01

10

00

0-

2.1%

2.7%

Oth

er P

rimar

y0

00

00

00

0-

--

Com

busti

ble R

enew

ables

and

Wast

e (no

t inc

lude

d ab

ove)

-1

11

-0

00

-1.

0%1.

0%To

tal P

rimar

y En

ergy

Sup

ply

(incl

udin

g C

RW)

-29

640

056

5-

100

100

100

-2.

0%2.

6%


Busi

ness

as

Usu

al P

roje

ctio

n: M

iddl

e Ea

st

1971

1990

1995

2010

2020

1971

1990

1995

2010

2020

1971

-199

519

95-2

010

1995

-202

0199

0-20

10C

ARB

ON

DIO

XID

E EM

ISSI

ON

Sm

illio

n to

nnes

CO

2pe

rcen

tage

sha

res

aver

age

annu

alto

tal

grow

th r

ate

grow

thM

obili

ty25

121

166

199

247

8.1%

1.2%

1.6%

65%

Foss

il fu

el S

tatio

nary

Use

s(I

ndus

try,S

ervi

ces,A

gric

ultu

re,H

ouse

hold

s)65

271

322

431

605

100

100

100

100

100

6.9%

2.0%

2.6%

59%

Solid

Fue

ls2

45

79

22

22

25.

0%2.

1%2.

7%58

%O

il36

203

227

276

359

5675

7064

597.

9%1.

3%1.

9%36

%G

as27

6590

148

237

4224

2834

395.

1%3.

4%3.

9%13

0%To

tal F

inal

Con

sum

ptio

n90

392

488

629

853

100

100

100

100

100

7.3%

1.7%

2.3%

61%

Solid

Fue

ls2

45

79

21

11

15.

0%2.

1%2.

7%58

%O

il62

323

393

474

606

6882

8175

718.

0%1.

3%1.

7%47

%G

as27

6590

148

237

3016

1824

285.

1%3.

4%3.

9%13

0%El

ectr

icity

Gen

erat

ion

(incl

. CH

P Pl

ants

)23

150

210

296

441

100

100

100

100

100

9.7%

2.3%

3.0%

97%

Solid

Fue

ls0

916

4361

06

814

14-

6.7%

5.5%

360%

Oil

1988

116

123

154

8458

5542

357.

8%0.

4%1.

2%41

%G

as4

5378

130

225

1636

3744

5113

.5%

3.4%

4.3%

143%

Oth

er T

rans

form

atio

n35

109

119

166

232

5.3%

2.2%

2.7%

52%

Solid

Fue

ls0

00

00

Oil

2942

4664

89G

as6

6773

102

143

Tota

l Em

issi

ons

148

651

817

1091

1526

100

100

100

100

100

7.4%

1.9%

2.5%

68%

Solid

Fue

ls1

1321

4971

12

35

511

.7%

5.9%

5.0%

267%

Oil

110

453

555

662

850

7470

6861

567.

0%1.

2%1.

7%46

%G

as37

185

242

381

605

2528

3035

408.

2%3.

1%3.

7%10

6%


Busi

ness

as

Usu

al P

roje

ctio

n: M

iddl

e Ea

st

POW

ER G

ENER

ATIO

N19

7119

9520

1020

2019

7119

9520

1020

2019

71-1

995

1995

-201

019

95-2

020

perc

enta

ge s

hare

sav

erag

e an

nual

gro

wth

rat

esEl

ectr

icity

Gen

erat

ion

(TW

h)28

327

513

839

100

100

100

100

10.8

%3.

0%3.

8%So

lid F

uels

019

5073

06

109

-6.

8%5.

6%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

00

00

00

00

--

-O

il20

149

171

235

7146

3328

8.8%

0.9%

1.8%

Gas

414

426

049

915

4451

6016

.0%

4.0%

5.1%

Nuc

lear

00

00

00

00

--

-H

ydro

416

3232

145

64

6.1%

4.9%

2.9%

Oth

er R

enew

able

s0

00

00

00

0-

6.8%

5.7%

Cap

acity

(GW

)-

8912

620

6-

100

100

100

-2.

4%3.

4%So

lid F

uels

-3

811

-4

66

-6.

6%5.

3%of

whi

ch C

ombu

stibl

e Ren

ewab

les a

nd W

aste:

-0

00

-0

00

--

-O

il-

4459

87-

4946

42-

2.0%

2.8%

Gas

-37

4997

-41

3947

-2.

0%4.

0%N

ucle

ar-

00

0-

00

0-

--

Hyd

ro-

510

10-

68

5-

4.9%

2.9%

Oth

er R

enew

able

s-

00

0-

00

0-

6.8%

5.7%


DEFINITIONS AND CONVERSION FACTORS ANNEX

This section of the 1998 WEO provides general information onthe fuel and sectoral definitions used throughout the Outlook, alongwith some approximate conversion factors. Readers interested inobtaining more detailed information should consult the IEApublications Energy Statistics of OECD Countries 1995-1996 (the‘red book’), Energy Balances of OECD Countries 1995 - 1996 (the‘blue book’) and Energy Statistics and Balances of Non-OECDCountries 1994-1995 (the ‘green book’).

Energy Definitions1

Solid FuelsFor the purposes of this Outlook the following definition of solid

fuels has been adopted. In the OECD countries solid fuels is equal tothe sum of coal and combustible renewables and waste (see below). Inthe non-OECD countries solid fuels only includes coal and thereforeexcludes combustible renewables and waste. When comparing thesolid fuels projections presented in this Outlook with data shown inrecent IEA statistical publications the reader should therefore pay closeattention to the definition of solid fuels being used in each publication.

CoalCoal includes all coal, both primary (including hard coal and

lignite) and derived fuels (including patent fuel, coke oven coke, gascoke, BKB, coke oven gas and blast furnace gas). Peat is also includedin this category.

Combustible Renewables & WasteCombustible Renewables & Waste comprises solid biomass and

animal products, gas/liquids from biomass, industrial waste and

1. The precise individual energy definitions used by the IEA can be found on pages I.5 and I.6 ofEnergy Balances of OECD Countries 1995-1996 (the ‘blue book’). Note that the Outlook’sregional definition of Solid Fuels differs from that used in recent IEA statistical publications.


municipal waste. Biomass is defined as any plant matter used directlyas fuel or converted into fuels or electricity and/or heat. Included hereare: wood, vegetal waste (including wood waste and crops used forenergy production), ethanol, animal materials/wastes and sulphite lyes.(Sulphite lyes are also known as “black liquor” and are an alkalinespent liquor from the digesters in the production of sulphate or sodapulp during the manufacture of paper. The energy is derived from thelignin removed from the wood pulp). Municipal waste compriseswastes produced by the residential, commercial and public servicesectors that are collected by local authorities for disposal in a centrallocation for the production of heat and/or power). Hospital waste isincluded in this category.

OilOil comprises the small quantity of crude oil (crude oil, natural

gas liquids, refinery feedstocks and additives as well as otherhydrocarbons) directly consumed and petroleum products (refinerygas, ethane, LPG, aviation gasoline, motor gasoline, jet fuels, kerosene,gas/diesel oil, heavy fuel oil, naphtha, white spirit, lubricants, bitumen,paraffin waxes, petroleum coke and other petroleum products). Notethat oil includes refineries own use of oil.

GasGas includes natural gas (both associated and non-associated gas,

but excluding natural gas liquids) and gas works gas.

NuclearThe nuclear data shown in the Total Primary Energy Supply

(TPES) tables refers to the primary heat equivalent of the electricityproduced by a nuclear plant with an average thermal efficiency of33%.

HydroThe hydro data shown in the TPES tables refers to the energy

content of the electricity produced in hydro power plants assuming100% efficiency. Hydro output excludes output from pumped storageplants.


Other RenewablesOther renewables includes geothermal, solar, wind, tide, wave

energy and the use of these energy forms for electricity generation.Unless the actual efficiency of the geothermal process is known, thequantity of geothermal energy entering electricity generation isinferred from the electricity production at geothermal plants assumingan average thermal efficiency of 10 per cent. For solar, wind, tide andwave energy, the quantities entering electricity generation are equal tothe electrical energy generated (i.e. 100% efficiencies). Direct use ofgeothermal and solar heat is also included in this category (whenreferring to TPES).

HeatHeat shows the disposition of heat produced for sale. The large

majority of the heat included in this category results from thecombustion of fuels, although some small amounts are produced fromelectrically powered heat pumps and boilers. Any heat extracted fromambient air by heat pumps is shown as indigenous production.

Other PrimaryOther Primary covers the small quantities of heat and electricity

entering directly into the Total Primary Energy Supply (TPES)balance.

Energy Related Service Sector Definitions

Electricity Electricity includes all electricity consumed in final consumption,

it therefore excludes own uses and losses, etc. Note that it also excludesheat consumption.

MobilityMobility includes all energy consumed in the transport sector

except electricity.

StationaryThe Stationary sector is equal to total final consumption of energy

minus total final consumption of electricity and all non-electricity


fuels in the Mobility sector. An equivalent definition of the Stationarysector is that it is the sum of non-electricity energy consumption in theindustry, residential, commercial, public service, agricultural, othersectors, non-specified and non-energy sectors.

Power GenerationPower Generation covers all inputs into electricity and CHP

plants. It includes both fossil and non-fossil inputs such as nuclear andrenewables.

Energy Balance Definitions

Indigenous ProductionIndigenous production is the production of primary energy, i.e.

hard coal, lignite, peat, crude oil, NGLs, natural gas, combustiblerenewables & waste, nuclear, hydro, geothermal, solar and the heatfrom heat pumps that is extracted from the ambient environment.Production is calculated after the removal of impurities.

Imports and ExportsImports and exports comprise amounts having crossed the

national territorial boundaries of the country, whether or not customsclearance has taken place.

International Marine BunkersInternational marine bunkers cover those quantities delivered to

sea-going ships of all flags, including warships. Consumption by shipsengaged in transport in inland and coastal waters is not included.

Stock ChangesStock changes reflect the difference between opening stock levels

on the first day of the year and closing levels on the last day of the yearof stocks on national territory held by producers, importers, energytransformation industries and large consumers. A stock build is shownas a negative number, and a stock draw as a positive number.


Total Primary Energy Supply (TPES)Total primary energy supply (TPES) is formally defined as

indigenous production + imports - exports - international marinebunkers ± stock changes. In the Outlook, however, the regional TPESexclude marine bunkers, whereas the world TPES includesinternational marine bunkers.

Statistical DifferencesStatistical differences is a category which includes the sum of the

unexplained statistical differences for individual fuels, as they appear inthe basic energy statistics. It also includes the statistical differences thatarise because of the variety of coal conversion factors.

Electricity PlantsElectricity plants refers to plants which are designed to produce

electricity only. If one or more units of the plant is a CHP unit (andthe inputs and outputs can not be distinguished on a unit basis) thenthe whole plant is designated as a CHP plant. Both public andelectricity plants are included.

Combined Heat and Power PlantsCombined heat and power plants (also known as autoproducer

plants), refers to plants which are designed to produce both heat andelectricity. Both public and autoproducer plants are included.

Total Final Consumption (TFC)Total final consumption (TFC) is the sum of consumption by the

different end-use sectors. In final consumption, petrochemicalfeedstocks are shown under industry, while non-energy use of such oilproducts as white spirit, lubricants, bitumen, paraffin waxes and otherproducts are shown under non-energy use, and are included in totalfinal consumption only. Backflows from the petrochemical industryare not included in total final consumption.

IndustryConsumption in the Industry sector includes the following sub-

sectors (energy used for transport by industry is not included here butreported under transport):


Iron and Steel Industry[ISIC Group 271 and Class 2731];Chemical industry [ISIC Division 24];of which: petrochemical feedstocks. The petrochemical industry

includes cracking and reforming processes for the purpose ofproducing ethylene, propylene, butylene, synthesis gas, aromatics,butadene and other hydrocarbon-based raw materials in processes suchas steam cracking, aromatics plants and steam reforming.

• Non-ferrous metals basic industries [ISIC Group 272 and Class2732];

• Non-metallic mineral products such as glass, ceramic, cement,etc. [ISIC Division 26];

• Transport equipment [ISIC Divisions 34 and 35];• Machinery. Fabricated metal products, machinery and

equipment other than transport equipment [ISIC Divisions 28,29, 30, 31 and 32];

• Mining (excluding fuels) and quarrying [ISIC Divisions 13 and14];

• Food and tobacco [ISIC Divisions 15 and 16];• Paper, pulp and print [ISIC Divisions 21 and 22];• Wood and wood products (other than pulp and paper) [ISIC

Division 20];• Construction [ISIC Division 45];• Textile and leather [ISIC Divisions 17, 18 and 19];• Non-specified (any manufacturing industry not included

above) [ISIC Divisions 25, 33, 36 and 37].

Transport SectorThe transport sector includes all fuels for transport except

international marine bunkers [ISIC Divisions 60, 61 and 62]. Itincludes transport in the industry sector and covers road, railway, air,internal navigation (including small craft and coastal shipping notincluded under marine bunkers), fuels used for transport of materialsby pipeline and non-specified transport. Fuel used for ocean, coastaland inland fishing is included in agriculture (other sectors).

Other SectorsOther sectors cover agriculture (including ocean, coastal and

inland fishing) [ISIC Divisions 01, 02 and 05], residential, commercial


and public services [ISIC Divisions 41, 50, 51, 52, 55, 63, 64, 65, 66,70, 71, 72, 73, 74, 75, 80, 85, 90, 91, 92, 93, 95 and 99], and non-specified consumption.

Non-EnergyNon-Energy covers all use of fuels for non-energy purposes. Non-

energy is included in total final consumption. It is assumed that theuse of these products is exclusively non-energy use. For example,petroleum products such as white spirit, paraffin waxes, lubricants andbitumen are consumed for non-energy reasons. Non-energy use of coalincludes carbon blacks, graphite electrodes, etc.

Other TransformationOther transformation is a diverse category and essentially covers

the energy consumed in converting primary energy into a form thatcan be consumed in the final consuming sectors. Examples of theenergy products produced by the other transformation sector includepetroleum products from crude oil and heat from fossil fuels via heatplants. Note that the other transformation sector excludes energyconsumption in electricity and CHP plants which are treatedseparately. Other transformation therefore includes transfers, statisticaldifferences, heat plants, gas works, petroleum refineries, coaltransformation, liquefication, other transformation, own use anddistribution losses.

Approximate Energy Conversion FactorsThis section provides approximate Mtoe (million tonnes of oil

equivalent) conversion factors for each of the major energy typesconsidered in this Outlook. Note that the standard unit usedthroughout this Outlook is tonne of oil equivalent (toe), where tonnerefers to a metric ton, i.e. 1000 kilograms. In order to convert to longand short tons use the following conversion factors; 1 tonne = 0.984long tons and 1 tonne = 1.1023 short tons.

OilThe following table is reproduced from Chapter 7 and shows the

regional and world conversion factors that existed in 1995 betweenmillion barrels of oil and million tonnes of oil equivalent (Mtoe). Note


that the relationship between barrels of oil and Mtoe is not exact butchanges over time for a variety of reasons, such as changes in thepetroleum product mix. For simplicity, it has been assumed that the1995 conversion factors continue to apply throughout the projectionperiod 1995-2020.

1995 World Oil Demand - Oil Market Report Basis

* The figure for China appears to be too low and that for OECD Pacific appears to be too high.These figures need further investigation.

** Pending submission of the detailed historical data needed to incorporate them into the OECD,the following OECD countries are shown in the IEA Oil Market Report (until August 1998) inthe relevant non-OECD regions: the Czech Republic and Poland in Non-OECD Europe, Koreain Other Asia and Mexico in Latin America. Note also that, whereas the OMR mbd includesmarine bunkers, the IEA mtoe does not.

Sources: Mtoe data are taken from the IEA statistical databases and the Mbd (million barrels perday) are taken from the Oil Market Report (OMR) dated 11 May 1998.

GasThe general conversion factor used throughout the Outlook for

gas is

1 trillion cubic feet of gas (tcf ) = 23.31 million tonnes of oilequivalent (Mtoe)

or equivalently1 Mtoe = 0.0429 tcf

Inland Demand Bunkers Total Total AggregateMtoe Mtoe Mtoe Mbd Barrels per toe

OECD 1832.2 70.99 1903.2 40.6 7.79North America** 873.3 27.7 901.1 19.8 8.02Europe** 650.2 36.0 686.2 14.1 7.50Pacific** 308.7 7.3 316.0 6.7 7.74*Non-OECD 1362.9 58.2 1421.1 29.5 7.58Transition Economies** 274.6 1.5 276.1 6.0 7.93Africa 96.9 8.3 105.2 2.2 7.63China 163.9 2.6 166.5 3.3 7.23*Other Asia** 362.6 22.4 385.0 7.9 7.49Latin America** 281.5 8.6 290.1 6.0 7.55Middle East 183.4 14.7 198.1 4.1 7.55World 3195.1 129.2 3324.3 70.1 7.70


In each of the three OECD regions gas has historically beenmeasured using different units, a general guide to these differentregional gas units vis-à-vis a tonne of oil equivalent is shown below.

Natural Gas

* e.g. 1 toe = 42.9 thousand cubic feet of gas.

CoalTrying to estimate conversion factors for coal is particularly

difficult as they depend on the precise definition of coal used and themix of different coals within the total. Details of how the IEA definescoal are shown above in the above Energy Definitions section.Comparing the Domestic Supply data for 1995 in original units, asshown in Energy Statistics of OECD Countries 1995-1996 (the ‘redbook’), with the Total Primary Energy Supply Mtoe data for 1995shown in Energy Balances of OECD Countries 1995-1996 (the ‘bluebook’) produces the following approximate conversion factors.

* e.g. 1.9 tonnes of coal = 1 tonne of oil equivalent in the case of OECD North America

ElectricityElectricity is generally measured in TWh (Terawatt hours). The

conversion factor used by the IEA to convert from TWh to Mtoe isshown below:

1 TWh = 0.086 Mtoe

Net Tonne of Oil Conversion Factor*

United States 42.9 thousand cubic feet (103ft3)

OECD Europe 1270 cubic metres (m3)

Japan 0.855 tonnes of LNG

Coal Tonnes of Coal per Tonne of Oil Equivalent*

OECD North America 1.9OECD Pacific 2.3 OECD Europe 2.7

OECD 2.2


Regional Definitions

OECD EuropeOECD Europe comprises the following 21 countries: Austria,

Belgium, Czech Republic, Denmark, Finland, France, Germany,Greece, Hungary, Iceland, Ireland, Italy, Luxembourg, Netherlands,Norway, Portugal, Spain, Sweden, Switzerland, Turkey and the UnitedKingdom. Although Poland joined the OECD in November 1996, atthe time of writing Polish energy data had not yet been incorporatedinto the IEA’s OECD Europe statistics. For the purpose of thisOutlook, Poland is therefore included in the Transition Economiesregion.

OECD North AmericaOECD North America consists of the United States of America

(US) and Canada. Although Mexico joined the OECD in 1994, it hasbeen included in the Latin American region for modelling purposes.

OECD PacificThe region includes Japan, Australia and New Zealand. Although

the Republic of Korea joined the OECD in 1996, it has been includedamongst other East Asian countries for modelling purposes. At thetime of writing the Republic of Korea’s energy data had not yet beenincorporated into the IEA’s OECD Pacific statistics.

Transition EconomiesThis region covers the countries of non-OECD Europe (Albania,

Bulgaria, Romania, Slovak Republic and Former Yugoslavia) and theFormer Soviet Union (Armenia, Azerbaijan, Belarus, Estonia, Georgia,Kazakhstan, Kyrgyzstan, Latvia, Lithuania, Moldova, Russia,Tajikistan, Turkmenistan, Ukraine and Uzbekistan). Although anOECD country since November 1996, Poland is also included herebecause at the time of writing Polish energy data had not yet beenincorporated into the IEA’s OECD Europe statistics. For statisticalreasons, this region also includes Cyprus, Gibraltar and Malta.

ChinaThis region comprises the whole of the People’s Republic of

China, including Hong Kong, which became a Special Administrativeregion of China in 1997. China excludes Chinese Taipei.


East AsiaEast Asia includes the following countries: Brunei, Democratic

People’s Republic of Korea, Indonesia, Malaysia, Myanmar,Philippines, Singapore, Republic of Korea, Chinese Taipei, Thailand,Vietnam, Fiji, French Polynesia, Kiribati, Maldives, New Caledonia,Papua New Guinea, Samoa, Solomon Islands, and Vanuatsu. In theIEA statistics, many small countries of Asia and Oceania are mergedtogether under the category of Other Asia. Since Afghanistan andBhutan are included in the Other Asia aggregate, it was not possible toseparate them out from the rest of Other Asia. Afghanistan and Bhutanhave therefore been excluded from the South Asia region. Thefollowing Asia and Oceania countries have not been considered due tolack of data: American Samoa, Cambodia, Christmas Island, CookIslands, Laos, Macau, Mongolia, Nauru, Niue, Pacific Islands (USTrust), East Timor, Tonga and Wake Island.

South AsiaThe South Asian region includes India, Pakistan, Bangladesh, Sri

Lanka and Nepal. For statistical reasons, Afghanistan and Bhutan areincluded in East Asia rather then South Asia (see the above definitionof East Asia for further details).

Latin AmericaThis region includes the following countries: Argentina, Bolivia,

Brazil, Chile, Colombia, Costa Rica, Cuba, Dominican Republic, ElSalvador, Ecuador, Guatemala, Haiti, Honduras, Jamaica, Mexico,Netherlands Antilles, Nicaragua, Panama, Paraguay, Peru,Trinidad/Tobago, Uruguay, Venezuela, Antigua and Barbuda,Bahamas, Barbados, Belize, Bermuda, Dominica, French Guiana,Grenada, Guadeloupe, Guyana, Martinique, St. Kitts-Nevis-Anguilla,Saint Lucia, St. Vincent-Grenadines, and Surinam. The followingcountries have not been considered in this Outlook due to lack of data:Aruba, British Virgin Islands, Caymen Islands, Falkland Islands,Montserrat, Saint Pierre-Miquelon and Turks, and Caicos Islands.

AfricaAfrica comprises the countries of North Africa (Morocco, Algeria,

Libya, Tunisia and Egypt), the Republic of South Africa, and all


countries of Sub-Saharan Africa, except Comoros, Namibia, SaintHelena, and Western Sahara, which have not been considered due tolack of data.

Middle EastThe Middle East region is defined as Bahrain, Iran, Iraq, Israel,

Jordan, Kuwait, Lebanon, Oman, Qatar, Saudi Arabia, Syria, UnitedArab Emirates and Yemen. It includes the neutral zone.

IEA PUBLICATIONS - 9, rue de la Fédération - 75739 PARIS CEDEX 15PRINTED IN FRANCE BY JARACH-LA RUCHE

(61 98 22 1P) ISBN 92-64-16185-6 – 1998

Documents

WORLD ENERGY OUTLOOK - Jean-Marc Jancovici · 11.9 Combined Cycle Gas Turbine Capacity (MW) 11.10 Nuclear Plants Under Construction and Completed: 1995-2000 11.11 OECD Europe Oil